From: Frey, Nathan J.

To: Wayland, Robertj; Culligan, Kevin

Cc: Higgins, Cortney; Laity, Jim

Subject: Summary of Interagency Comments Under EO 12866 & 13563 -- EGU NSPS NPRM 2060-AQ91

Date: Friday, August 02, 2013 8:46:28 PM

Attachments: Summary of Interagency Comments under EO_12866_13563 EGU_GHG_NSPS_2060-AQ91_NPRM.docx

Summary of Interagency Comments Under EO 12866 13563 EGU NSPS_2060_AQ91.docx

Attached please find a summary of interagency comments under EOs 12866 and 13563 regarding

the EPA proposed rule, Standards of Performance for Greenhouse Gas Emissions from New

Stationary Sources: Electric Utility Generating Units. Thanks and please let us know if you have any

questions.

Nathan
Summary of Interagency Working Comments on Draft Language under

EO12866 Interagency Review.  Subject to Further Policy Review.

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Summary of Interagency Comments on U.S. Environmental Protection Agency’s Notice of Proposed

Rulemaking “Standards of Performance for Greenhouse Gas Emissions from New Stationary Sources:

Electric Utility Generating Units” (RIN 2060‐AQ91)

General comments:

 EPA plans to prepare a separate Federal Register notice rescinding the April 13, 2012 proposal.  

The commenter would appreciate the opportunity to review that notice.   

 Has EPA considered whether there is any ongoing benefit or significance to the rationale that

was put forth in the April 2012 proposal, and whether the April 2012 justification is

complementary to the rationale set forth in this proposal?

 EPA demonstrates that no reasonable forecast predicts a cost advantage to building an

electricity generating unit (EGU) that would not be compliant with the proposed standard.  

Given that, what is the rationale for promulgating the rule? EO 12866 states that “federal

agencies should promulgate only such regulations as are required by law, are necessary to

interpret the law, or are made necessary by compelling public need, such as material failures of

private markets.”  Can EPA clarify whether this rule is required by law or necessary to interpret

the law?    

EPA notes that the rule would provide regulatory certainty and thereby incentivize innovation.  

It is unclear how a regulation that would not require any change in behavior would incentivize

companies to invest in technologies to further reduce emissions, unless there were external

market forces that would prompt them to do so.  In which case, the regulation would not be

needed.  Can EPA explain this line of thinking further?

 What is the legal justification for providing an exemption to Wolverine should it not have

commenced construction by publication?

 According to some technical experts, we understand that it may be possible to design and

construct a hybrid EGU that combusts both coal and gas.  How would such a plant be treated for

purposes of NSPS compliance?

Best System of Emission Reduction (BSER):

 The commenter requests clarification on whether EPA’s definition of BSER enables other

technologies that meet the same level of emissions reduction (e.g., chemical looping and oxy‐

combustion).

 For the proposition that CAA section 111 standards may impose a greater compliance burden on

some sources in a category (page 179‐185), EPA may also wish to cite the recent case of

Portland Cement Ass’n v. EPA, 665 F.3d 177 (D.C. Cir. 2011).  In Portland Cement, the court

upheld EPA’s approach that focused “primarily” on cement kilns with a newer design

incorporating a state‐of‐the‐art technology, rather than older‐designed kilns that would become

subject to the NSPS if modified.  EPA found that the older‐designed kilns had available controls

that could enable them to meet the standard, but noted that it would be “more difficult” for
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them and would entail somewhat higher cost; thus, EPA considered separate standards for the

older kilns but ultimately decided against that approach.

 Although not stated explicitly, the justification for reasonable cost seems to imply that the net

compliance costs must be negative, that the revenue from EOR must fully offset the increased

cost of partial CCS.  If this is the correct interpretation, it could potentially set a restrictive

precedent that carbon pollution standards only have reasonable cost if they are expected to be

cost‐saving irrespective of environmental benefits.  Again, while the rule doesn’t state this

explicitly, we note that in table 4 the levelized cost of electricity under the standard with high

EOR is equal to or less than cost without CCS for both SCPC and IGCC.  EPA may wish to clarify

whether costs could still be considered “reasonable” under this analytical framework if EOR

revenue estimates did not lower net costs to the level of an uncontrolled plant.   

Additionally, while EPA considers the revenue from EOR to lower overall costs, the preamble

doesn’t appear to consider additional CO2 emissions from recovered fossil fuels to be an

environmental disbenefit.  Should the recovery and combustion of fossil fuel from EOR that

would otherwise remain underground be considered in the economic analysis?

 EPA states that it is logical and a reasonable interpretation of the statute that the costs of the

control technology should be offset by any revenues from the sale of pollutants or pollution

control byproducts associated with those controls.  Has EPA applied this logic in any other NSPS

(or other similar and relevant context)?  See page 160.  It would be helpful to further elaborate

on this issue in the preamble.

Level of standard:

 The commenter suggests that the range on which comments are solicited for the proposed

emission limit for new fossil fuel‐fired boilers and IGCC units be amended from 1,000 – 1,200 lb

CO2 / MWh to [900] – 1,200 lb CO2 / MWh. The lower bound of this range, which we tentatively

suggest to be [900], would be at a level slightly above the feasible level exemplified by the Great

Plains Synfuels Plant and the Kemper County Energy Facility—which appears to be

approximately 900 lb CO2 / MWh. The economic analysis in the rule and the RIA did not provide

strong reason to think that such plants would be unduly expensive in the future, and the fact

that these are being built in fact suggests that they are not unduly expensive currently and thus

could be consistent with BSER.

 Can EPA provide additional explanation and justification for why it is appropriate to set the BSER

level at 45% capture, as opposed to a higher or lower level of partial capture?  It would be

helpful to have more detail on why the chosen level (as opposed to other levels) was selected,

and the basis for that determination.  For example, can more detail be provided on the

thresholds or tipping points for capture above which costs jump significantly?  Or is there

greater evidence of the achievability of this level of capture based on real‐word experience?  If

so, further explanation could help strengthen the BSER determination section of the preamble.  

(We note that EPA has provided some detail on the technical reasons for the choice (e.g. it is

cheaper to use a single “water gas shift” cycle in part because the resulting syngas does not

require a specialized H2 turbine that would be required if multiple water gas shifts are used,
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yielding up to 90% capture and more or less pure H2), but think the overall justification still

needs further elaboration.

 In section VII.L “Compliance Period” EPA proposes a 60 operating‐month compliance period for

new fossil fuel‐fired boiler and IGCC units. In contrast, the April 2012 draft rule proposed a 30‐

year compliance period. What data and analysis method is EPA using to interpolate between the

April 2012 proposal (1,000 lb CO2 MWh with full CCS” and 30‐year compliance period) and the

regulations currently applicable to these sources, in order to arrive at the proposal under

consideration (950‐1,050 lb CO2 MWh with “partial CCS” and 60‐operating‐month compliance

period)? Please point the reviewer to the data and analysis that support the proposed 60‐

operating‐month compliance period.

 Page 89. Can EPA provide an example of how the 75% credit for useful thermal output would

factor into compliance determinations?

 Page 327‐328.  The discussion of parasitic loads and gross‐ versus net‐based standards could be

improved by tabulating the relevant SCPC and IGCC coal plants, with and without CCS, thereby

demonstrating the parallel gross and net standards and how these were calculated and inter‐

relate.  Otherwise, the text as currently written states that 1400 lbCO2/MWh would be the net

basis for a coal‐CCS plant, which differs little from the (gross) coal without CCS performance

numbers noted for high performing units of 1434 lbCO2/MWh (p. 188; p. 200), at least at first

blush without the benefit of the parallel display of figures.  Below is a sample table cobbled

together from numbers reported in the FR – the square parentheses represent imputed

numbers rather than stated in the text.

Gross Emissions

(lbCO2/MWh)

Parasitic Load Net Emissions

(lbCO2/MWh)

SCPC 1675 ‐ 1783 <7.5% [1800 ‐ 1916]

IGCC 1434 15% [1649]

Coal‐CCS 1100 [27%] 1400

NGCC (<=850

MMBtu)

1100 2.5% 1130

NGCC (>850

MMBtu)

1000 2.5% 1030

Simple Cycle/Peaking plants:   

 The rule clearly states that the intended facilities to be covered are intermediate and baseload

generation and exempts “peaking” plants.  While the rule provides a reasonable justification for

treating these sources differently than intermediate or baseload generation, why were these

sources exempted rather than setting a less stringent numerical standard for this subcategory?  

Given that availability of peaking plants is an enabling technology for renewable electricity, we

could imagine that uncontrolled simple cycle plants could lead to higher overall power sector

carbon emissions. Did EPA analyze this scenario as it relates to interactions with renewable

energy growth?

 The commenter agrees with EPA’s determination that simple cycle units should not be subject

to the same standards as combined cycle units. However, rather than entirely exempting simple
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cycle units, EPA could formulate an alternative standard in recognition of the role simple cycle

units play in complementing renewable sources and maintaining grid reliability. Are there plans

to propose a standard that would apply to simple cycle units?  If so it might be appropriate to

mention such plans.  This could be quite significant because of the increasingly important role

expected to be played by simple cycle natural gas turbines as wind and solar power generation

expands.

 Page 142. EPA states: “Second, only 0.2 percent of existing simple cycle turbines had a three‐

year average capacity factor of greater than 33 percent between 2000 and 2012. Therefore, as

noted, from a practical standpoint, few new simple cycle turbines be subjected to the standards

of performance in this rulemaking.” It would be good to see the distribution curves here,

because this still could impact some simple cycle turbines, raising the question of flexibility in

implementation.  With a projected increase in reliance on cyclical solar and wind power,

presumably the amount of load following turbine cycling might be expected to increase.  Maybe

EPA has a graph that could be circulated as a memo?

 Page 144. EPA states: “Only 0.4 percent of existing simple cycle turbines had an annual capacity

factor of greater than 40 percent between 2000 and 2012.” On the previous page EPA

commented on only 0.2 percent over 3 years at 33%.  Presumably the percent calculation

differences relate to the time and rate input parameters, but it is a little confusing.  Hence, a

graph and memo would be helpful.

 Page 145. EPA states: “For example, a 33 percent efficient 100 MW facility would have a

potential electric output of 876,000 MWh and a 40 percent efficient 100 MW facility would have

a potential electric output of only 723,000 MWh.” I don’t understand the math here, whereas it

was clear in the previous conversion of 25MW to a 219000 MWh annual equivalent.  This

calculation would seem to be 0.33 x 100 MW x 24 hr x 365 = 289080 MWh, but it is not.  It also

seems unusual that the less efficient plant has a higher potential electric output.  Recommend a

brief explanation of how the numbers are calculated, perhaps in a footnote.   

 EPA should explain why smaller NGCC units meet a particular need.  Is it geographic specific?  Is

there a possibility that multiple new smaller units would be built instead of one larger unit?

Technical feasibility of CCS for coal‐fired units:

 The draft NSPS regulation is “technology forcing” for carbon capture and storage (CCS) in that it

establishes partial CO2 capture using CCS as the Best System of Emission Reduction (BSER) for

new fossil‐fuel boilers and integrated gasified combined cycle (IGCC) units.  The commenter

agrees that carbon capture is technically feasible, but it has not been deployed at scale in

commercial power plants.  The commenter also agrees that Enhanced Oil Recovery (EOR)

sequestration has been employed commercially.  Nevertheless, demonstration projects will be

necessary in a number of operating environments in order to reach the technical potential and

the cost targets contemplated in the rule, and to demonstrate storage in saline aquifers.  The

commenter therefore believes the rule should incorporate sufficient flexibility to enable

additional demonstration projects.  This will ensure that the draft NSPS regulation is “technology

forcing” for both carbon capture technologies and sequestration, whether EOR or geologic.
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 EPA’s assertion of the technical feasibility of carbon capture relies heavily on literature reviews,

pilot projects, and commercial facilities yet to operate.  We believe this cannot form the basis of

a finding that CCS on commercial‐scale power plants is ‘adequately demonstrated.”

o EPA should provide details of the specific CCS operations already in service that process

the rate of CO2 necessary for a typical IGCC power plant to be in compliance.  Where

only literature reviews or simulations exist, the text should make this clear.  

o We are concerned that the unsupported assertions of technology as ‘adequately

demonstrated’ in this rulemaking will form a precedent for future such determinations,

even if the three CCS projects used as the basis for the determination fail or are never

completed.

 EPA states that the level of the NSPS standard “best promotes further enhancement of the

performance of existing technology and promotes continued development of new, better

performing technology” (See page 199).   Could EPA further explain why it believes that a

standard level that can be met by existing technologies would spur development of new, better

performing technology?   Presumably, this is because we would expect a higher volume of CCS

deployment at this cheaper capture level, thereby helping to develop the production experience

needed to lower costs for related technologies that could ultimately be used to achieve higher

capture rates.  Further explanation on this topic would be helpful.  

 Why is the Boundary Dam project not included in the listing of CCS demonstration projects

(starting on page 212)?  It is mentioned in two other places in the FR, as well as getting a prime

place in EPA’s introductory powerpoint.

Costs of CCS:

 Can EPA please provide a brief explanation (on page 29) of why the cost of partial 65% capture

are so much less than full 90% capture?  This is made more evident in RIA Table 5‐7, p.5‐19,

where the capital increment for partial‐65% CCS is estimated at $305/kW, with a further

$812/kW capital to get to full‐90% CCS.  Presumably this relates to additional technologies being

added to a coal fired plant to go from partial to full capture, but the differential is quite high

since much of the capital expenditure would presumably have gone into the IGCC and basic

capture components.  A technical explanation would be helpful.   

 Page 219, Table 4. The NGCC @ $5.0/MMBtu estimate is actually substantially below the EIA

2013 estimate, in $2011, even if we extract the transmission costs.  EIA reported $65.6 – $1.2

transmission = $64.4, compared to NETL/EPA $52. Is this difference fully explained by the range

of modeled gas cost input prices, and, if so, might this calculation/explanation warrant a

footnote?

 Attached are CCS costs prepared by DOE’s National Energy Technology Laboratory (NETL) based

on two NETL studies, as well as current project cost data.  These numbers provide a range of

cost estimates for next‐of‐a‐kind plants.  The commenter believes that it would be appropriate

for the proposed rule to consider the full range of cost estimates developed by NETL,

recognizing the level of uncertainty in these estimates.   
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The commenter notes that DOE is sponsoring research on novel carbon capture technologies

and alternative coal conversion technologies that may substantially lower future CCS costs.

 EPA states that “regulatory programs may serve to defray the costs of CCS, including, for

example, Clean Energy Standards or guaranteed electricity purchase price agreements.”  This is

the only discussion of these policies.  EPA should discuss this further, instead of just mentioning

them.  (See page 230)

 Regarding transportation of CO2, it is not clear that the preamble addresses the costs that may

be associated with any new pipelines that could be used for transportation, and specifically the

cost to get CO2 from a facility to a GS site.  It would be helpful for EPA to include a more

detailed discussion on transportation (page 205).

 EPA should clarify the assumptions and estimates of costs associated with transportation of fuel,

electricity and/or CO2 in its assessment of “reasonable costs.”  See also related comments

below regarding the RIA and NETL’s consideration of transportation costs.  

o EPA’s analysis assumes the cost of CO2 transportation is not “a significant impediment”

to CCS, based on a history of CO2 pipelines and the distribution of existing CO2 sources.    

Instead, EPA should acknowledge that other factors can vary significantly the cost of

CO2 transport. availability (or unavailability) of rights‐of‐way for new pipelines; capital

costs; and operating costs (in terms of dollars, energy, and GHG emissions).

o EPA discusses siting considerations as if they are costless (pp. 242).  Additional siting

considerations increase the cost of construction by requiring trade‐offs in that may not

have existed in the absence of the regulatory mandate.  These costs include

transportation of coal and delivery of electricity from a location that would otherwise

not be selected.  As with CO2 transportation, these costs include availability (or

unavailability) of rights‐of‐way for new pipelines or rail lines; capital costs; and

operating costs (in terms of dollars, energy, and GHG emissions). Again, see RIA

comments noting NETL’s acknowledgment of variability in such costs.

o EPA asserts that gas can serve as a substitute when appropriate siting for a coal‐fired

power plant is unavailable (pp 241).  This implies the assumption that national electric

markets are entirely integrated and electricity is a commodity with no regional

variations. Further, though EPA assumes the baseline and regulated scenarios are

equivalent, it is possible that resource and technology development paths between

these two differ, thus weakening the strength of this assumption.  We suggest EPA add

language to further acknowledge the substantial uncertainty related to this assumption.   

Geologic Sequestration:

 The commenter requests that EPA clarify that this rule does not require a switch from Class II to

Class VI.

 Please note existing questions to EPA regarding the hazardous waste exemption rule for Class VI

wells, and whether this should and could be extended in a separate rulemaking to UIC Class II

wells that have monitoring, reporting, and verification (MRV) procedures consistent with GHG

Reporting Rule Subpart RR.  The FR text on page 255, refers to the use of both UIC Class II and
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Class VI wells under GHG Reporting Rule SubPart RR as verification of sequestration for the

purposes of the NSPS.   

 EPA’s BSER determination for coal‐fired plants would benefit from a more clear explanation of

the factual basis for determining that the long‐term storage of CO2 has been demonstrated. The

preamble discussion should be strengthened on this topic.

o Specific comment on p. 205: Can EPA provide a more direct explanation of how the

permanence of storage has been demonstrated?  The preamble talks about how storage

locations and opportunities are available for geologic sequestration and EOR, but it does

not discuss evidence that CO2 can actually be technically stored for long periods of time.  

It is our understanding that such evidence exists, and it should be explained.

o Specific comment on p. 212: EPA notes that alternatives to geologic sequestration

would need to address the – “ultimate fate of the captured CO2 and the degree to

which the method permanently isolates the CO2 from the atmosphere” – but EPA does

not describe in the preamble how its proposal meets addresses these points.  EPA

should explain its rationale and provide the supporting evidence. See also page 208 and

page 260.

 EPA’s proposal will have significant disparate geographic impacts.  Geologic features appropriate

for EOR or geologic sequestration are not evenly distributed throughout the country. (See also

related comments regarding RIA and NETL assumptions below).   EPA asserts that such disparate

impacts are permitted by the Clean Air Act, citing some legislative history (see e.g., pp 180‐181).

However, these quotations apply to the impact of the NAAQS provisions (i.e., local sources

effect on local pollution), and the possible restrictions on construction of new sources in non‐

attainment areas.  The NSPS is a uniform emission standard for the whole country, imposed

regardless of local levels of pollution.  It is more inappropriate to exercise this discretion in this

case, where local pollution does not have local effects.

o We believe EPA confuses the legislative history regarding the distinction between a

geographic restriction on new sources due to NAAQS and due to NSPS.  EPA similarly has

not distinguished between s siting considerations due to the regulated entity’s selected

technology and due to EPA’s mandate of an “adequately demonstrated” technology that

cannot be used in particular places (pp. 242).   

o EPA reminds us that the DC Circuit has said that sec. 111 standards “must not give a

competitive advantage to one State over another in attracting industry.”  Please explain

how this instruction is consistent with a sec. 111 standard that is unattainable in parts of

the country.

o We would like to know of any other NSPS for which the “adequately demonstrated”

technology was inappropriate for particular parts of the country, without respect for

NAAQS or PSD.

 How will EPA enforce the requirement that captured CO2 be reported under the GHG reporting

program?  Is that requirement an explicit part of the “standard of performance” and therefore

enforceable like any other part of the standard?  (see page 255).  We note that EPA is relying on

MRV plans that are required under Subpart RRR of the GHG Reporting program to detect and

quantify leakage (see page 252).  What is not clear is what happens under Subpart RRR if

leakage occurs.  EPA should discuss this aspect of the overall approach.
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 If a covered entity meets the standard by capturing CO2 and sending it to a facility covered by

the GHG reporting program but the geologic storage facility shows high leakage rates, would

EPA have any ability to remedy the leakage problem or pursue enforcement action against

anyone? It would be helpful to describe the agency’s thinking on this point.  

CCS for Natural Gas:

 EPA states that NGCC is not “technically feasible” (on page 33, 264, and others), yet on page 265

notes that there is a demonstration project, which implies that CCS is technically feasible for

NGCC.  EPA does helpfully note that CO2 concentrations are lower in effluent from NGCC

relative to coal‐fired power plants. Are there are other technical constraints to actually using

CCS in the NGCC context?  Or, are there financial and efficiency drivers involved that limit the

use of CCS in the NGCC industry that should be further explained?   

 Presumably, EPA has decided to set a GHG standard for new natural gas‐fired facilities that does

not require additional emissions control technology because it is relatively cheaper to achieve

the same level of emissions reductions from existing fossil fuel‐fired power plants (via a

subsequent rulemaking). However, EPA does not appear to have provided any estimates on

what it would actually cost new natural gas‐fired facilities to install and operate CCS technology.

Isn’t data and analysis on the cost of applying CCS to natural gas‐fired facilities necessary in

order to justify the decision that CCS is not BSER for new natural gas‐fired facilities?  

 Because the rule considers CCS for natural gas infeasible there is no cost analysis of this option.  

The preamble provides evidence for why there is greater uncertainty in applying CCS for natural

gas than coal; however, EPA may wish to request comment and attempt a cost analysis for the

final rule.  If nothing else, this may signal to the industry that CCS could be considered for

natural gas during the statutorily‐required 8‐yr review.  

The preamble asserts that CCS technology is increasingly difficult for natural gas plants that

cycle to provide intermittent load, however, would it be possible to create a subcategory for

baseload NGCC generation that would be more likely to meet BSER criteria? If that is the case,

EPA may consider requesting comment on further subcategorization.

 Although technology that would make CCS for natural gas an efficient way to reduce emissions

is not currently available, it would be desirable for EPA to signal that were technology to be

demonstrated and to meet BSER criteria, then EPA would accordingly reexamine whether

NGCC/CCS would meet BSER criteria in its next NSPS review cycle.  Sending such a signal should

serve to support R&D in natural gas CCS.  One way for EPA to send this signal would be by

including a cost analysis and a request for comment on CSS for natural gas in the final rule,

although there might be better ways to send this signal.

 The briefing materials and draft NSPS Federal Register notice state that EPA does not have

sufficient information to determine if CCS for natural gas is technically feasible.  Recognizing

that we are parsing the text closely here given legal requirements, we believe that more care

needs to be taken in the selection of words and phrasing.  To be clear, we agree that NG‐CCS has

not been “adequately demonstrated,” that we do not have sufficient economic information to
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determine if NG‐CCS costs are reasonable, and there are differences in system design and CO2

concentrations, etc., between coal and gas power plants.  That said, in discussions with industry

and academics we have been informed that all aspects necessary for NG‐CCS have been

demonstrated, albeit not configured, funded, or implemented.  Concerns about the need for

hydrogen turbines in certain configurations are not dissimilar from the considerations relating to

coal syngas.  In support, we note the BP‐SSE Peterhead precombustion NG‐CCS proposal in

Great Britain that was cancelled due to delays in UK government funding; the current Shell‐SSE

Peterhead Post‐Combustion NG‐CCS finalist proposal in the British CCS competition; and recent

news reports from GE‐Sargas and Summit‐Linde that they are independently proceeding with

NG‐CCS design and funding proposals.   

o http://ieahia.org/pdfs/PeterheadCase_Study1_2.pdf

o https://www.gov.uk/government/news/preferred‐bidders‐announced‐in‐uk‐s‐1bn‐ccs‐

competition

o http://sequestration.mit.edu/tools/projects/peterhead.html

o http://www.businesswire.com/news/home/20120619005970/en/GE‐Sargas‐Announce‐

Alliance‐Enhanced‐Oil‐Recovery

o http://bellona.org/ccs/ccs‐news‐events/news/article/summit‐power‐and‐linde‐join‐

forces‐to‐develop‐ccs‐for‐gas‐fired‐power‐generation.html

With these in mind, we recommend that EPA carefully re‐evaluate the text so as not to impugn

efforts in the direction on NG‐CCS.  We suggest the following edits:  

o Page 32: “By contrast, NGCC with CCS is not a configuration that is widely being planned

and built today. The EPA considered whether NGCC with CCS could be identified as the

best system of emission reductions adequately demonstrated for new stationary

combustion turbines, and we decided that it could not be identified for several reasons.

At this time, CCS has not been implemented for NGCC units, and we believe there is

insufficient information to make a determination regarding the technical feasibility of

implementing CCS at these types of units. The EPA is aware of only one NGCC unit that

has implemented CCS on a very small portion of its exhaust stream. The EPA is not

aware of any demonstrations of NGCC units implementing CCS technology that would

justify setting a national standard. Further, the EPA does not have sufficient information

on the prospects of transferring the coal‐based experience with CCS to NGCC units. In

fact, CCS technology has primarily been applied to gas streams that have a relatively

high to very high concentration of CO2 (such as that from a coal combustion or coal

gasification unit). The concentration of CO2 in the flue gas stream of a coal combustion

unit is normally about four times higher than the concentration of CO2 in a natural gas‐

fired unit. Natural gas‐fired stationary combustion turbines also operate differently from

coal‐fired boilers and IGCC units of similar size. The NGCC units are more easily cycled

(i.e., ramped up and down as power demands increase and decrease). This cyclical

operation, combined with the already low concentration of CO2 in the flue gas stream,

lead to uncertainty about how technically feasible CCS technology might be

demonstrated is for NGCC units absent further information. [note: GE‐Sargas propose

using an aeroderivative turbine with multiple shafts to maintain gas pressures (to aid in

capture) at varying turbine rates.]

o Page 264: “We do not consider full or partial capture CCS to be BSER because of these

technologies have not been adequately demonstrated and there are uncertainties
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regarding the economic about technical feasibility and because of adverse impacts on

electricity prices and the structure of the electric power sector.”

o Page 265: “First, we do not consider that are uncertain as to whether full or partial

capture CCS has been adequately demonstrated is technically feasible for this source

category.”

o Page 266. Recommend deleting paragraph beginning “Moreover, identifying partial or

full CCS as the BSER for new stationary combustion turbines would have significant

adverse effects on national electricity prices, electricity supply, and the structure of the

power sector.” Please reconsider how the text here could adversely impact other

current and future efforts to move the US toward developing additional CCS

technologies relevant to natural gas and other industrial sources, and revise the

language accordingly.  This text should not foreclose on future regulatory rationales for

technological advancements and GHG pollution reduction, as most of these will always

have costs that will need to be weighed against the relevant benefits, at that time.  We

do not have sufficient information on the current cost of NG‐CCS, which is enough per

se not to move ahead with this as BSER.  In future, we may have adequate

demonstrations and economic information, at which time EPA may choose to evaluate

costs against the benefits of reducing the social cost of carbon and related impacts in

reaching its future decision, rather than just “we cannot do it because it costs more.”

o Page 266. EPA states: “We recognize that identifying full or partial CCS would as the

BSER for this source category would result in significant emissions reductions, but at

present, we already consider natural gas to be a low‐GHG‐emitting fuel and NGCC to be

a low‐emitting technology.” Recommend replacing “this source category” with “new

stationary combustion turbines.”

o Powerpoint: “we do not have the information to determine if it is technically feasible.”

Reject CCS because it has not been adequately demonstrated.   

Oil‐fired power plants:

 Our understanding from the introductory oral presentation is that EPA is not including oil‐fired

power plants under either the coal or natural gas NSPS requirements.  Hence, Hawaiian power

plants would not be included under the NSPS, and there would be no need for a non‐continental

exclusion.  However, no such exclusion or discussion is in the FR text, and the Da regulatory

language relates to all burning of fossil fuels in steam generating units.  The only discussions of

oil fired power plants imply that these are included under the NSPS for steam and IGCC units (p.

2‐3; footnote 3 on page 20 includes oil; p. 99 liquid fuels; p.103 fuel oil, appears linked to gas;

p.108 oil‐fired exempt from acid rain program; p.119 “but not liquid‐fired sources”).  There is no

mention of Hawaii.  Could EPA please clarify whether oil fired power plants are in the NSPS, and

how the standard relates to Hawaii and non‐continental emission sources.   

 Page 81, EPA states: “Note that we are not proposing standards for new steam generating units

and stationary combustion turbines that sell less than 1/3 of their potential output to the grid,

new non‐natural gas‐fired stationary combustion turbines, existing sources undertaking

modifications or reconstructions, or certain projects under development as discussed below.”

Can EPA provide an example of a “new non‐natural gas‐fired stationary combustion turbine?”  

Does this mean oil, and/or Hawaii, and how is this legally implemented in the Subpart Da and

KKKK regulatory text sections?
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 Page 119, EPA states: “Rather, the EPA is simply promulgating new standards of performance for

CO2 emissions from certain sets of sources, e.g., boilers and turbines, but not liquid‐fired

sources.” How is such a “liquid‐fired source” exclusion implemented in the actual regulatory

requirements under Da and KKKK?

Combined heat and power:  

 The commenter supports appropriate incentives for combined heat and power (CHP) and

suggests further consideration of its treatment under the rule to reflect associated emissions

benefits.

Biomass:

 How does EPA propose to handle new fossil fuel‐fired power plants that also rely on some

percentage of renewable fuel? What percentage of renewable biomass would be necessary to

offset the GHG emission contributions of the fossil fuel to the GHG emissions rate, as measured

by the facility?

 The commenter requests further consideration of the treatment of biomass emissions,

particularly as it relates to the use of biomass co‐firing, to reflect its potential emissions

benefits.

 How would biomass emissions be calculated for purposes of compliance with the NSPS?  If that

will be determined by EPA’s forthcoming rulemaking on biogenic carbon emissions for GHG

permitting, should that be mentioned in the preamble?

 Notes from EPA’s oral presentation indicate that biomass is being treated the same as coal in

these NSPS standards (p. 28).  Does the recent court decision on biomass change this decision

(URL below)?  What plans does EPA have to develop a regulatory structure that would empower

an appropriate use and consideration of the benefits of biomass power generation?

http://www.eenews.net/greenwire/2013/07/15/stories/1059984404  

PSD and Title V Program:

 The commenter recommends adding the language in redline to the following discussion (on

page 262):  “As noted in the ‘Implications for PSD and Title V programs’ section of this preamble,

some states have authority to issue PSD permits. In other cases, the EPA issues the permit.

States with approved permitting programs have some discretion in making permit decisions and

including the necessary conditions of the permit to ensure the enforceability of the permit,

subject to EPA’s oversight role.  Defendants in enforcement cases frequently raise “state

permitting discretion” as a defense, so it would be useful to clarify this sentence about state

discretion by mentioning EPA’s oversight role.”  See, e.g., Alaska Dept. of Environmental

Conserv. v. EPA, 540 U.S. 461, 486 (2004) (affirming EPA’s “broad oversight role” for Best

Available Control Technology determinations in the Prevention of Significant Deterioration (PSD)

permitting process).

 The commenter recommends adding the language in redline to this discussion (on page 278):  

“Under the PSD program in part C of title I of the CAA, in areas that are classified as attainment
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or unclassifiable for NAAQS pollutants, a new or modified source that emits any air pollutant

subject to regulation at or above specified thresholds is required to obtain a preconstruction

permit. This permit assures that the source meets specified requirements, including application

and operation of best available control technology.”  The new text recognizes that the PSD

program also imposes operational obligations.  Defendants sometimes latch onto the term

“preconstruction” to argue that PSD obligations end after construction.  

 In section IX.E “Implications for Title V fee requirements for GHGs” EPA proposes two options

for how to account for the increased costs to states of reviewing and issuing permits to facilities

that emit GHGs under the Title V program. However, the preamble does not provide enough

information to allow the reader to compare the two proposals. Which is more likely to lead to

states charging adequate fees? Which is more likely to appeal to states that do not wish to

charge adequate fees?  

Emissions Trading:

 Why not attempt to introduce trading emissions credits as a method of compliance? Is it clear,

for example, that reducing GHG emissions by 30 percent from three EGUs is more expensive

than reducing GHG emissions by 90 percent from one of the three (assuming each facility

generates CO2 at the same rate)?  

 EPA may wish to discuss whether emissions trading options would be economically efficient and

legally possible in this regulation.  While this rule is not expected to result in new compliance

costs and therefore trading would not lower overall costs, we generally seek flexible

mechanisms that have the potential to lower costs while providing the same environmental

benefit.   

From our reading, the preamble is silent to the concept of trading under section 111 of the

Clean Air Act, though, to our knowledge, the courts have not explicitly ruled against it. One

concern is that if trading would be a preferred option to address carbon emissions from existing

sources, should this regulatory action do everything possible to enable that outcome?  For

example, if a trading system could be defined as the best system of emission reduction (BSER)

for reducing carbon emissions from power plants, should that be defined here in the rule for

new sources?   

Additionally, when and how would future power plants built to comply with these standards be

re‐categorized existing sources, and would these plants be able to trade with existing sources

under 111(d) if trading is not an option under 111(b)?  As an illustration, we would assume that

a new coal plant built with full CCS should be able to trade under an existing source trading

program, would that be allowed if the standard for new sources doesn’t allow trading?

Existing sources:

 Is it necessary for EPA to promulgate standards of performance for GHG emissions from new

sources before the agency can legally promulgate standards of performance for GHG emissions

from existing sources?
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 EPA’s discussion of BSER for coal continues to raise significant concerns about future actions as

they relate to existing sources. Please provide further language to clarify EPA’s position

regarding existing sources.  For example, EPA asserts that “identifying partial CCS as the BSER for

coal will be beneficial to coal‐fired electric generation . . . .” (pp. 240), by eliminating uncertainty

and forestalling future Federal controls that might require CCS.  The logical implications of this

statement and the subsequent discussion will be perceived as a threat of future requirements

for existing sources.   

o Because the BSER for gas‐fired plants is NGCC without CCS, these plants must therefore

“face the risk that future state or federal controls may require carbon capture, which . . .

, is a particularly expensive proposition.”

o If partial CCS now can forestall a “particularly expensive proposition” for future existing

sources (that is, sources built now under the NSPS), then EPA appears to be saying that

currently existing coal‐fired power plants also face the risk of future requirements for

CCS.

o EPA does not dispel the possibility that a partial CCS BSER now would be replaced with a

full CCS requirement for future existing sources.

 Even though EPA states that this rule applies to newly constructed units, does EPA anticipate

that the existing plants would face competitive pressures from the newly constructed units that

will potentially be able supply energy more cheaply, effectively forcing the existing plants into

upgrading their equipment which would mean they would also need to meet the new standard?

If this is the case, EPA should take into account ex‐post compliance costs for the existing plants.   

Regulatory Impact Analysis:

General comments

 Clarify language regarding environmental benefits. Given that EPA is assuming the baseline and

regulatory scenarios to be essentially equivalent, any language implying the draft rule will “limit”

GHG emissions should be changed to state the rule is setting standards for emissions. “Limit”

implies an incremental benefit resulting from the rule. See, e.g., first sentence of Sec. 1.1 in ES

of RIA.    

 Clarify baseline years and period of analysis. The RIA refers to a base year of 2020, achieving

negligible changes by 2020, and an analysis period defined through 2022. Please clarify.

 What is the impact of the CSAPR legal decisions on the use of this rule in the baseline? Please

clarify the role of CSAPR given its current status.  

 Has EPA consulted with NRC and FERC regarding the assumed growth in nuclear capacity?

 Please review and, if appropriate, revise footnote 72, potentially substituting the term “justify”

for the term “necessary” to make the language consistent with Executive Orders relevant to

Benefit Cost considerations.  EO 13563 reiterates EO 12866 that “each agency must, among

other things: (1) propose or adopt a regulation only upon a reasoned determination that its

benefits justify its costs (recognizing that some benefits and costs are difficult to quantify) ... (3)

select, in choosing among alternative regulatory approaches, those approaches that maximize
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net benefits (including potential economic, environmental, public health and safety, and other

advantages; distributive impacts; and equity);”

State of CCS technology

 Chapter 4, clarify Sec.4.5 to reflect the current developmental state of CO2 control technology.  

EPA’s own BACT guidance and the NETL study both acknowledge the formative state of CCS

technology. In addition, while IGCC projects are under development, only a handful of such

plants currently exist in the world.  The language in this section reads as if IGCC and CCS are

well‐established and already in widespread commercial practice.  Please provide further

explanation.  This discussion should list the exact number of completed plants currently

employing the discussed technologies, the size/maximum capacity of these plants and allowable

under current technology, any geographic limitations (such as altitude and temperature

considerations for IGCC), projects currently in development, including those for which

investment ceased, and plants with significant cost overrun issues. If the agency prefers, some

of this detail could be presented in Chapter 5 of the RIA.

 Page 5‐28. EPA assesses that any new coal‐fired plant that might be built could incorporate

carbon capture technologies in a way that would not be cost‐prohibitive.  Are there any existing

coal‐fired plants that use carbon capture technology?  How did EPA generate its estimate of the

additional levelized cost of energy of CCS (p. 5‐49)?  

The RIA also states that 70% of the CCS projects underway plan to use the captured carbon for

enhanced recovery of oil.  Are any of these projects being implemented by coal‐fired plants?

 EPA’s analysis of cost and capacity suffer a significant selection bias because it relies on idealized

and currently executed CCS projects and government economic incentives. (See RIA 5‐7.)

o Economic incentives for current CCS projects are not generalizable to the entire coal

industry or into the future because these are limited to only certain firms in the

following ways:  

 Time: Significant funding for the economic incentives alluded to in the RIA come

from legislation designed to stimulate the economy during a recessionary period

by increasing spending in a specific time period. These incentives then are likely

to expire as the economy improves.

 Eligible projects: tax benefits from the State of Texas for CCS projects were

capped at the first three major projects to qualify for the benefits.

 Complex application processes: Department of Energy financial assistance and

USDA CO2 capture project loans are limited to those who follow the necessary

application process

 Limited funds: Department of Energy had a set amount of funds that they could

use to incentivize projects as part of the Clean Coal Power Initiative Round III

and therefore must prioritize its assistance

 Contrast: The incentives for nuclear power and other industries cited by EPA

(see pp.226‐7) are generally long‐standing and available to all firms in the

industry, without application and not subject to appropriations.

o EPA’s analysis of the feasibility and cost effectiveness of CCS technology centers on 2‐3

specific examples of uncompleted CCS projects.
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 None of the CCS systems in active projects are fully running. These projects also

have cost and schedule overruns that may contradict some of the EPA’s

idealized estimates

 The Southern Kemper County Project is experiencing substantial cost

overruns of hundreds of millions dollars

 The Texas Clean Energy Project (TCEP) was supposed to start

construction in Fall 2011 but had not started as of March 2013

 The EPA is understating the amount of financial assistance that each of the CCS

projects mentioned in the preamble is receiving. In addition to DOE cost sharing

programs as part of the ARRA, these projects are receiving millions of dollars in

Federal tax credits from the IRS as well as assistance from state and local

governments

 For example, the TCEP has received $450 million (over a quarter of the

projected project cost) in cost sharing from the DOE and an additional

$100 million from the ARRA. TCEP also benefited from a limited Texas

State law that provided over $100 million in tax benefits as well as

additional tax benefits for EOR.  

 By only looking at a couple of examples, the EPA is understating the

overwhelming cost and risk factors that have forced previous government‐

supported CCS projects to be de‐scoped, tabled, or shut down  

 Of the 6 projects funded by the Department of Energy’s Clean Coal

Power Initiative Round III half have been forced to withdraw from the

program. According to the Congressional Research Service, these

projects have significantly de‐scoped, tabled, or shut down due to cost

overruns or uncertainty regarding the effectiveness and efficiency of the

CCS technology.

Natural Gas Price Assumptions

 Page 5‐23 to 5‐24. The regulatory impact analysis assess that for a new coal‐fired EGU without

carbon capture to reach price parity with a natural gas EGU, the price of natural gas would have

to rise to $10/MMBtu and that this price would exceed the most pessimistic forecast by about

30%.  We understand that the forecasts include assumptions related to macroeconomic

conditions, markets, etc.  Would the model control for a shock to natural gas prices prompted

by changes in U.S. export policy or trade policy?   

For example, under current policy, liquefied natural gas (LNG) cannot be exported without a

finding from the Department of Energy that such export is in the public interest.  Exports to Free

Trade Agreement partner countries are deemed automatically to be in the public interest.  

Should the U.S. successfully conclude the TransPacific Partnership (TPP) trade negotiations (with

Japan as a TPP member and one of the world’s largest LNG importers) and/or trade negotiations

with the EU, this would presumably lead to a large increase in exports to these regions. A study

by DOE predicted that increased exports (resulting from current pending applications but not to

future exports to new FTA partners) would increase the domestic price of LNG by $.22 – 1.11

(2010$/McF).  Would such increases be accounted for in your model?  

 The EPA’s assessments of energy prices and electricity demand rely on data biased by poor

economic conditions
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o According to the producer price index, real prices for energy have increased

substantially since the time of the EPA’s analysis in the RIA. This development means

that the EPA’s analysis will likely understate future energy price increases.

o By largely representing a recessionary period, the EPA’s data reflects extraordinarily low

electricity demand due to a contracting economy, a trend that has started to reverse

itself as the economy moves out of the recession. Therefore, the EPA’s analysis will

likely undervalue the future demand for electricity.

o Natural gas prices are historically volatile. Where there has recently been some stability

in prices this stabilization has occurred after the period of time that the EPA is analyzing

in the RIA and should be taken into account as the EPA may understate future natural

gas prices.

NETL study.

 EPA tabulates and relies primarily on NETL estimates of the LCOE for the various energy

generation sources.  We are more familiar with the annual EIA numbers, and these differ from

the NETL values, for instance EIA (2013) estimates the LCOE for NGCC at $65.6/MWhr, whereas

NETL/EPA estimate $52/MWhr.  A number of the tables actually provide footnotes identifying

the EIA numbers, which is very helpful.  The recommendation is that such footnotes be provided

once, early on, and with a brief explanation of why the numbers differ, beyond just the

subtraction of the transmission cost estimates.

 Clarify NETL analysis as based on simulations/models and literature reviews and state key

assumptions. Please see below for specific suggested further clarifications regarding the NETL

study.

- Clarify NETL’s assessment of the analyzed technology. Please acknowledge in EPA’s

discussion, the following NETL statements/findings. In addition, provide further

explanation as to how EPA came to the conclusion that partial CCS is BSER (incl.

emissions limit) given the NETL assessments. For example, have new facilities come

on line since this study, or have new innovations occurred?

 Page 37, NETL. “The post‐combustion CO2 removal technology for the PC

capture cases is immature technology.  This technology remains unproven

at commercial scale in power generation applications.”

 Page 37‐38, NETL. “The pre‐combustion CO2 removal technology for the

IGCC capture cases has a stronger commercial experience base.  Pre‐

combustion CO2 removal from syngas streams has been proven in chemical

processes with similar conditions to that in IGCC plants, but has not been

demonstrated in IGCC applications.  While no commercial IGCC plant yet

uses CO2 removal technology in commercial service, there are currently

IGCC plants with CO2 capture well along in the planning stages.”

 Page 33‐34, NETL.  Environmental targets for IGCC were chosen to match

EPRI’s design basis for Coal Fleet for Tomorrow Initiative. EPRI notes these

designs are ‘targets’ and not to be used for permitting values.  Further as of

the report publication, NETL states there are 4 operating IGCC’s worldwide

that use a solid feedstock and are primarily power producers (Polk, Wabash,

Buggenum, & Puertollano). Further (p. 26, NETL), the NETL Aspen

simulations assume zero elevation, which is optimal for IGCC performance.  
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- Clarify that ‘slip stream’ cost‐effectiveness was determined through literature

review. (5‐18) The RIA states that NETL determined the slip stream approach to be

the most cost‐effective.  At several points the NETL study (see, e.g., p. 2, 22, 77)

states it made this determination via literature review.  It should be made clear that

this determination was not made through either simulation or direct analysis of data

or actual case studies. Further EPA should state whether it has any actual data on

the cost‐effectiveness of the slip stream approach. This might include noting

whether the literature NETL reviewed used empirical data.

- Clarify expected accuracy of NETL estimates.  Exhibit 2‐15, p. 37 of the NETL study

notes that cost estimates are expected to vary by ‐15% to ‐30% on the low side and ‐

20% to +50% on the high side. This uncertainty should be reflected in the Chapter 5

tables.  

- Clarify uncertainty of transportation (TS&M) estimates.  P. 47, NETL.  NETL states

cost metrics for TS&M are “costs for a ‘favorable’ sequestration project, and may

vary significantly based on variables such as terrain to be crossed by the pipelining,

reservoir characteristics, and number of landowners from which sub‐surface rights

must be acquired.” Further, NETL assumes transportation costs for the IL No. 6 coal

will be 25% of mine mouth costs based on the Midwestern region with limestone

available within a few states (Morgantown WV).  Is this assumption applicable to

costs in other regions of the US?  

- Clarify cost assumptions regarding substitutability of NGCC, IGCC and coal w/partial

CCS.  Please provide further explanation for this assumption including citations

where relevant.  The NETL study EPA that references notes that simulations indicate

electricity and capital costs for SC PC w/CCS v. GEE IGCC w/CCS vary according to

level of CO2 capture.  At lower levels, coal is cheaper for the owner with costs

converging to roughly equivalent at above 90% capture.  What levels of

emissions/CO2 is EPA assuming when making this substitutability assumption?

- Clarify CSAPR/MATS v. NETL baselines. The NETL study assumes the 2006/2007 NSPS

is in place but does not discuss CSAPR/MATS. Does EPA anticipate any significant

tensions in these assumptions? Alternatively, did EPA make adjustments in IPM to

accommodate the more current baseline? E.g. the NETL study assumes model plants

use IL No. 6 high‐sulfur bituminous coal whereas CSAPR and MATS differ in both

coal use (PRB) and transport assumptions. In addition, the RIA should add a

footnote recognizing the recent CSAPR decision.  While the analytics of the current

legal environment would prove difficult to capture in the baseline, it is noteworthy

that the decision found certain requirements to be too stringent for some states,

which could (or not) in turn impact the level of control technology put in place.  

- Clarify net capacity assumptions in relation to industry. The NETL study assumes 550

MWe for SC PC and a range of 523‐622 MW for IGCC.  How does this assumption

relate to regulated entities?  What, if any, technology limitations might exist for

larger facilities?

- Clarify the impact of NETL’s within the fenceline assumption. While NETL considers

capital and transport costs, these are limited to within the fenceline of the facility.  

Did EPA make any adjustments to its cost estimates for costs associated with

pipeline investments and operating costs beyond the fenceline? If not, why? Is 50

miles/80km as assumed by NETL expected to be typical pipeline distance?
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Paperwork Reduction Act

 This rule should impose no additional paperwork burden, since EPA asserts that this rule will

have a negligible economic impact and a no “notable” CO2 emission reductions.   

o The PRA disfavors reporting and recordkeeping requirements intended simply to remind

a regulated entity that substantive regulations exist.  All information collections must

have practical utility, which means the information gathered must be actually used

rather than have a potential use.

o If industry will proceed as it is, with or without the rule, EPA should eliminate any

reporting or recordkeeping requirements associated with the NSPS, since there will be

nothing to enforce.

o CO2 emissions appear to be a function of the design of the electricity generating unit.  

Thus, if a new technology appears, CO2 emissions can be modeled as part of the existing

permitting and reporting processes in place of emissions monitoring requirements.  

o For those units for which CCS can be operated at variable rates, existing GHG reporting

requirements should be sufficient to ensure compliance with the NSPS.

o Alternatively, all units subject to the NSPS should be exempted from the separate GHG

reporting requirements.

Editorial/technical comments:

Preamble

 On page 31, section 6 is entitled “[w]hat is BSER for fossil fuel‐fired stationary combustion

turbines?” This would appear to refer both to natural gas fired and coal fired power plants.  

However, the discussion in section 6 is limited to natural gas fired power plants.   

 The commenter recommends the deletion of the text in strike out in the following sentence (on

page 68):  “A modification is ‘any physical change . . . or change in the method of operation . . .

which increases the amount of any air pollutant emitted by such source or which results in the

emission of any air pollutant not previously emitted,’ unless it is a specific type of change,

exempt from consideration as a modification, such as installation of pollution control projects.  

The validity of the pollution control project (PCP) exemption for NSPS has never been litigated,

but it might be prudent to avoid highlighting the issue because the parallel PCP exemption for

New Source Review was vacated in New York v. EPA, 413 F.3d 3 (D.C. Cir. 2005).

 Discussion of Coordination with Other Rules Applicable to Power Plants (page 74):  The

commenter recommends revision of this sentence as follows:  “The EPA recognizes that it is

important that each of these regulatory efforts achieves its intended environmental objectives

in a common‐sense, cost‐effective manner that is consistent with the underlying statutory

requirements and that minimize impacts on electricity rates and assures a reliable power

system.”  Because the sentence already mentions that EPA is attempting to be “cost effective,”

the reference to minimizing impacts on electric rates is redundant.  Also, the commenter would

prefer to avoid discussion of rate impacts because it is problematic for power plant

enforcement.  Utilities frequently raise rate impacts as a reason for delaying or avoiding

compliance once they are found in violation of the CAA.   

 EPA should add the language in redline to the following sentence (on page 114):  “Therefore,

with this 40 percent sales criterion on a single‐year basis, as a practical matter, it is anticipated
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that few new simple cycle turbines would be subject to the proposed standards of

performance.”

 Page 134. Please check latest estimates of sea level rise. The likely range for sea level between

2080 and 2100 from the AR5 is between 0.26m (10 inches) and 0.81m (31 inches) with most of

the uncertainty having to do with emissions scenarios.  Although higher than 7 – 23 inches, this

is not “twice as large or more.”

 For consistency with the New Source Review Program, please substitute the following text in

redline (on page 240): “In addition, identifying partial CCS as the BSER for coal will be beneficial

to coal‐fired electric generation, and therefore fuel diversity, over the long term. This is because

Identifying partial CCS as BSER eliminates uncertainty as to future control obligations for coal‐

fired capacity. Any new coal‐fired source that constructs without CCS faces the risk that future

state or federal controls may require carbon capture, which would require the source to retrofit

CCS, which, in turn, is a particularly expensive proposition. This risk is heightened because

power plants are generally long‐livedhave expected lives of 30 to 40 years and the risk of future

carbon limitations can be expected to remain throughout that period.”  

 Page 273, in Discussion of Emission Rates for Smaller‐Size Units:  Please ask EPA if there is a

technical error in the following sentence so that the second use of “1000” should read “1100”:  

“Two of the small combined cycle facilities had a maximum 12‐operating‐month rolling average

emissions rate equal to or greater than 1,000 lb CO2/MWh and one had an maximum 12‐

operating‐month rolling average emissions rate equal to or greater than 1,000 lb CO2/MWh.”   

(The rule establishes an emissions limit of 1100 lb CO2/MWh for certain smaller units.)

Regulatory Impact Analysis

 Page 4‐25, middle of the page: “Friday, June 7th” should be “June 7, 2013.”  

 Page 5‐1, second paragraph, last sentence before the bullet points: Should 2022 be 2020? We

thought the analysis went through 2020 per page 1‐2, which says every eight years is 2020.

 Page 5‐2, drop “likely” from the phrase “the proposed EGU GHG NSPS would likely provide net

social benefits” given that the benefit cost ratio is clearly positive under a wide range of

assumptions.

 Page 5‐2, middle of the page, second full paragraph, second sentence, part (3): should the word

solid be added? On page 2‐6, it appears that solid fossil‐fired EGUs are a separate category.

 Given that the rule extends to 2022, suggest EPA to include IPM projections for 2025 in addition

to 2020 in Tables 5‐1 and 5‐3 to enhance clarity of information presentation. EPA could also

consider including IPM results for 2030 to enhance comparison with AEO 2013 presented in the

same tables.  

 Page 5‐34, clarify why the ratio of total CO2 emissions (3.0/2.7) is lower than the ratio of CO2

emissions rates (1,400/1,200), for the IGCC and SCPC, respectively.  Also, drop “of these

technologies” in paragraph 5.7.   
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 Page 5‐37, To avoid confusion, note in FN a that the updated SCC values were presented

originally in the April 2013 TSI using 2007$.

 Page 5‐42, In table 5‐X double check the valuations attached to the PM2.5 benefits since it is

surprising that these are comparable to the CO2 related benefits, particularly since these

estimates use the updated higher SCC values and reference new coal plants with relatively low

PM emissions.

 Table on 5‐44, second column.  Should this show PM2.5 dis‐benefits?  According to the table on

pg 5‐34, the SO2 emissions increase by about 1/3 from 23 to 30lbs/MWh.   

 Page 5‐49, “To evaluate the potential revenues from EOR we estimate the revenue in each

scenario if CO2 could be sold for $20/ton based on [update source of estimate].” Yes, this is an

important input number.  Please update.

 Table 5‐X, p.5‐49.  The bottom line (last row) numbers in these tabulated calculations could be

made a lot clearer by adding a plus sign before the right digits in the paired presentation.  

Currently, the text: << ‐$7.1 ‐ $38 >> reads as if there are negative benefits (which is a bad thing)

from negative seven to negative thirty‐eight dollars.  Tracing the actual math leading to this

reveals that the $38 is actually positive, hence the suggestion to affirmatively add the plus sign

to << ‐$7.1 ‐ +$38 >>.  Same with the other columns.

Citations

 Page 40 Footnote 9, Page 130 Footnote 89 (Citation of the Coalition for Responsible Regulation

Case):  Here is the missing citation:  Coalition for Responsible Regulation, Inc. v. Environmental

Protection Agency, 684 F.3d 102 (D.C. Cir.), reh’g en banc denied, 2012 U.S. App. LEXIS 25997,

26313 (D.C. Cir. 2012), petitions for cert. filed, No. 12‐1253 (U.S. Apr. 2013).

 Page 73 Footnote 61 (Citation of the Las Brisas Case):  EPA may use this citation to the

December 13, 2012 order:  Las Brisas Energy Center, LLC v. Environmental Protection Agency,

No. 12‐1248, 2012 U.S. App. LEXIS 25535 (D.C. Cir. Dec. 13, 2012).
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EO12866 Interagency Review.  Subject to Further Policy Review.

EO 12866_EGU GHG NSPS 2060-AQ91 NPRM_20130628 

6560-50-P 

ENVIRONMENTAL PROTECTION AGENCY 

40 CFR Part 60 

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

RIN 2060-AQ91 

Standards of Performance for Greenhouse Gas Emissions from New 

Stationary Sources: Electric Utility Generating Units

AGENCY: Environmental Protection Agency (EPA). 

ACTION: Proposed rule. 

SUMMARY: On April 13, 2012, the EPA proposed a new source 

performance standard for emissions of carbon dioxide for new 

affected fossil fuel-fired electric utility generating units. 

The EPA received more than 2.5 million comments on the proposed 

rule. After consideration of information provided in those 

comments, as well as consideration of continuing changes in the 

electricity sector, the EPA determined that revisions in its 

proposed approach are warranted. Thus, in a separate action, the 

EPA is rescinding the April 13, 2012 proposal, and in this 

action, the EPA is proposing new standards of performance for 

new affected fossil fuel-fired electric utility steam generating 

units and stationary combustion turbines. This action proposes a 

separate standard of performance for fossil fuel-fired electric 
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utility steam generating units and integrated gasification 

combined cycle units that burn coal, petroleum coke and other 

fossil fuels that is based on partial implementation of carbon 

capture and storage as the best system of emission reduction. 

This action also proposes standards for natural gas-fired 

stationary combustion turbines based on modern, efficient 

natural gas combined cycle technology as the best system of 

emission reduction. 

DATES: Comments. The EPA previously proposed a new source 

performance standard for emissions of carbon dioxide (CO2) for 

new affected fossil fuel-fired electric utility generating units 

(EGUs) on April 13, 2012 (77 FR 22392). The EPA considered 

comments submitted in response to the original April 13, 2012 

proposal in developing this new proposal. However, we are 

rescinding the original proposal. If you would like 

consideration of comments submitted on the April 13, 2012 

rulemaking, you should submit new comments or re-submit previous 

comments. Commenters who submitted public comments concerning 

any aspect of the previous proposal will need to consider the 

applicability of those comments to this current proposal and 

submit them again, if applicable, even if the comments are 

exactly or substantively the same as those previously submitted, 

to ensure consideration in the development of the final 
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rulemaking. Comments must be received on or before [INSERT THE 

DATE 60 DAYS AFTER THE DATE OF PUBLICATION IN THE FEDERAL 

REGISTER OF THIS PROPOSED RULE]. Under the Paperwork Reduction 

Act (PRA), since the Office of Management and Budget (OMB) is 

required to make a decision concerning the information 

collection request between 30 and 60 days after [INSERT THE DATE 

OF PUBLICATION IN THE FEDERAL REGISTER OF THIS PROPOSED RULE], a 

comment to the OMB is best assured of having its full effect if 

the OMB receives it by [INSERT THE DATE 30 DAYS AFTER THE DATE 

OF PUBLICATION IN THE FEDERAL REGISTER OF THIS PROPOSED RULE]. 

 Public Hearing. The EPA will hold a public hearing (or 

hearings) on this proposal. The date, time, and location of the 

public hearing (or hearings) will be announced separately in a 

subsequent Federal Register notice. Oral testimony will be 

limited to five minutes per commenter. The EPA encourages 

commenters to provide written versions of their oral testimonies 

either electronically or in paper copy. The rulemaking docket 

will include verbatim transcripts and written statements. If you 

would like to present oral testimony at one of the hearings, 

please notify Ms. Pamela Garrett, Sector Policies and Programs 

Division (C504–03), U.S. EPA, Research Triangle Park, NC 27711, 

telephone number (919) 541–7966; email: garrett.pamela@epa.gov. 

Persons wishing to provide testimony should notify Ms. Garrett 
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at least two days in advance of the public hearings. The public 

hearings will provide interested parties the opportunity to 

present data, views, or arguments concerning the proposed rule. 

EPA officials may ask clarifying questions during the oral 

presentations but will not respond to the presentations or 

comments at that time. Written statements and supporting 

information submitted during the comment period will be 

considered with the same weight as any oral comments and 

supporting information presented at the public hearing. For 

updates and additional information on the public hearings, 

please check the EPA’s website for this rulemaking, 

http://www.epa.gov/airquality/carbonpollutionstandards. 

ADDRESSES: Comments. Submit your comments, identified by Docket 

ID No. EPA-HQ-OAR-2013-0495, by one of the following methods: 

At the website http://www.regulations.gov: Follow the 

instructions for submitting comments. 

At the website http://www.epa.gov/oar/docket.html: Follow 

the instructions for submitting comments on the EPA Air and 

Radiation Docket web site. 

E-mail: Send your comments by electronic mail (e-mail) to 

a-and-r-docket@epa.gov, Attn: Docket ID No. EPA-HQ-OAR-2013-

0495. 

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

Mail: Send your comments to the EPA Docket Center, U.S. 

EPA, Mail Code 2822T, 1200 Pennsylvania Ave., NW, Washington, DC 

20460, Attn: Docket ID No. EPA-HQ-OAR-2013-0495. Please include 

a total of two copies. In addition, please mail a copy of your 

comments on the information collection provisions to the Office 

of Information and Regulatory Affairs, OMB, Attn: Desk Officer 

for EPA, 725 17th St. NW, Washington, DC 20503. 

Hand Delivery or Courier: Deliver your comments to the EPA 

Docket Center, EPA West, Room 3334, 1301 Constitution Ave., NW, 

Room 3334, Washington, DC, 20460, Attn: Docket ID No. EPA-HQOAR-2013-0495. Such deliveries are accepted only during the 

Docket Center’s normal hours of operation (8:30 a.m. to 4:20 

p.m., Monday through Friday, excluding federal holidays), and 

special arrangements should be made for deliveries of boxed 

information. 

 Instructions: All submissions must include the agency name 

and docket ID number (EPA-HQ-OAR-2013-0495). The EPA’s policy is 

to include all comments received without change, including any 

personal information provided, in the public docket, available 

online at http://www.regulations.gov, unless the comment 

includes information claimed to be Confidential Business 

Information (CBI) or other information whose disclosure is 
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restricted by statute. Do not submit information that you 

consider to be CBI or otherwise protected through 

http://www.regulations.gov or e-mail. Send or deliver 

information identified as CBI only to the following address: 

Roberto Morales, OAQPS Document Control Officer (C404-02), 

Office of Air Quality Planning and Standards, U.S. EPA, Research 

Triangle Park, North Carolina 27711, Attention Docket ID No. 

EPA-HQ-OAR-2013-0495. Clearly mark the part or all of the 

information that you claim to be CBI. For CBI information on a 

disk or CD-ROM that you mail to the EPA, mark the outside of the 

disk or CD-ROM as CBI and then identify electronically within 

the disk or CD-ROM the specific information you claim as CBI. In 

addition to one complete version of the comment that includes 

information claimed as CBI, you must submit a copy of the 

comment that does not contain the information claimed as CBI for 

inclusion in the public docket. Information so marked will not 

be disclosed except in accordance with procedures set forth in 

40 CFR part 2. 

 The EPA requests that you also submit a separate copy of 

your comments to the contact person identified below (see FOR 

FURTHER INFORMATION CONTACT). If the comment includes 

information you consider to be CBI or otherwise protected, you 
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should send a copy of the comment that does not contain the 

information claimed as CBI or otherwise protected. 

 The www.regulations.gov website is an “anonymous access” 

system, which means the EPA will not know your identity or 

contact information unless you provide it in the body of your 

comment. If you send an email comment directly to the EPA 

without going through http://www.regulations.gov, your email 

address will be automatically captured and included as part of 

the comment that is placed in the public docket and made 

available on the Internet. If you submit an electronic comment, 

the EPA recommends that you include your name and other contact 

information in the body of your comment and with any disk or CDROM you submit. If the EPA cannot read your comment due to 

technical difficulties and cannot contact you for clarification, 

the EPA may not be able to consider your comment. Electronic 

files should avoid the use of special characters, any form of 

encryption, and be free of any defects or viruses. 

 Docket: All documents in the docket are listed in the 

http://www.regulations.gov index. Although listed in the index, 

some information is not publicly available (e.g., CBI or other 

information whose disclosure is restricted by statute). Certain 

other material, such as copyrighted material, will be publicly 

available only in hard copy. Publicly available docket materials 
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are available either electronically in 

http://www.regulations.gov or in hard copy at the EPA Docket 

Center, EPA West, Room 3334, 1301 Constitution Ave., NW, 

Washington, DC. The Public Reading Room is open from 8:30 a.m. 

to 4:30 p.m., Monday through Friday, excluding federal holidays. 

The telephone number for the Public Reading Room is (202) 566-

1744, and the telephone number for the Air Docket is (202) 566-

1742. Visit the EPA Docket Center homepage at 

http://www.epa.gov/epahome/dockets.htm for additional 

information about the EPA’s public docket. 

 In addition to being available in the docket, an electronic 

copy of this proposed rule will be available on the Worldwide 

Web (WWW) through the Technology Transfer Network (TTN). 

Following signature, a copy of the proposed rule will be posted 

on the TTN’s policy and guidance page for newly proposed or 

promulgated rules at the following address: 

http://www.epa.gov/ttn/oarpg/. 

FOR FURTHER INFORMATION CONTACT: Mr. Christian Fellner, Energy 

Strategies Group, Sector Policies and Programs Division (D243-

01), U.S. EPA, Research Triangle Park, NC 27711; telephone 

number (919) 541-4003, facsimile number (919) 541-5450; email 

address: fellner.christian@epa.gov or Dr. Nick Hutson, Energy 

Strategies Group, Sector Policies and Programs Division (D243-
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01), U.S. EPA, Research Triangle Park, NC 27711; telephone 

number (919) 541-2968, facsimile number (919) 541-5450; email 

address: hutson.nick@epa.gov. 

SUPPLEMENTARY INFORMATION: Acronyms. A number of acronyms and 

chemical symbols are used in this preamble. While this may not 

be an exhaustive list, to ease the reading of this preamble and 

for reference purposes, the following terms and acronyms are 

defined as follows: 

AB Assembly Bill 

AEP American Electric Power 

AEO Annual Energy Outlook 

ANSI American National Standards Institute 

ASME American Society of Mechanical Engineers 

ASTM American Society for Testing of Materials 

BACT Best Available Control Technology 

BDT Best Demonstrated Technology 

BSER Best System of Emission Reduction 

Btu/kWh British Thermal Units per Kilowatt-hour 

Btu/lb British Thermal Units per Pound 

CAA Clean Air Act 

CAIR Clean Air Interstate Rule 

CBI Confidential Business Information 

CCS Carbon Capture and Storage (or Sequestration) 

CDX Central Data Exchange 

CEDRI Compliance and Emissions Data Reporting Interface 

CEMS Continuous Emissions Monitoring System 

CH4 Methane 

CHP Combined Heat and Power 

CO2 Carbon Dioxide 

CSAPR Cross-State Air Pollution Rule 

DOE Department of Energy 

DOT Department of Transportation 

ECMPS Emissions Collection and Monitoring Plan System 

EERS Energy Efficiency Resource Standards 

EGU Electric Generating Unit 

EIA Energy Information Administration 

EO Executive Order 

EOR Enhanced Oil Recovery 
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EPA Environmental Protection Agency 

FR Federal Register 

GHG Greenhouse Gas 

GW Gigawatts 

H2 Hydrogen Gas 

HAP Hazardous Air Pollutant 

HFC Hydrofluorocarbon 

HRSG Heat Recovery Steam Generator 

IGCC Integrated Gasification Combined Cycle 

IPCC Intergovernmental Panel on Climate Change 

IPM Integrated Planning Model 

IRPs Integrated Resource Plans 

kg/MWh Kilogram per Megawatt-hour 

kJ/kg Kilojoules per Kilogram 

kWh Kilowatt-hour 

lb CO2/MMBtu Pounds of CO2 per Million British Thermal Unit 

lb CO2/MWh Pounds of CO2 per Megawatt-hour 

lb CO2/yr Pounds of CO2 per Year 

lb/lb-mole Pounds per Pound-Mole 

MATS Mercury and Air Toxic Standards 

MMBtu/hr Million Metric British Thermal Units per Hour 

MW Megawatt 

MWe Megawatt Electric 

MWh Megawatt-hour 

N2O Nitrous Oxide 

NAAQS National Ambient Air Quality Standards 

NAICS North American Industry Classification System 

NAS National Academy of Sciences 

NETL National Energy Technology Laboratory 

NGCC Natural Gas Combined Cycle 

NRC National Research Council 

NSPS New Source Performance Standards 

NSR New Source Review 

NTTAA National Technology Transfer and Advancement Act 

O2 Oxygen Gas 

OMB Office of Management and Budget 

PC Pulverized Coal 

PFC Perfluorocarbon 

PM Particulate Matter 

PM2.5 Fine Particulate Matter 

PRA Paperwork Reduction Act 

PSD Prevention of Significant Deterioration 

PUC Public Utilities Commission 

RCRA Resource Conservation and Recovery Act 

RFA Regulatory Flexibility Act 

RGGI Regional Greenhouse Gas Initiative 
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RIA Regulatory Impact Analysis 

RPS Renewable Portfolio Standard 

SBA Small Business Administration 

SCC Social Cost of Carbon 

SCR Selective Catalytic Reduction 

SF6 Sulfur Hexafluoride 

SIP State Implementation Plan 

SNCR Selective Non-Catalytic Reduction 

SO2 Sulfur Dioxide 

SSM Startup, Shutdown, and Malfunction 

Tg Teragram 

Tpy Tons per Year 

TSD Technical Support Document 

TTN Technology Transfer Network 

UIC Underground Injection Control 

UMRA Unfunded Mandates Reform Act of 1995 

U.S. United States 

USGCRP U.S. Global Change Research Program 

VCS Voluntary Consensus Standard 

WGS Water Gas Shift 

WWW Worldwide Web 

Organization of This Document. The information presented in 

this preamble is organized as follows: 

I. General Information 

A. Executive summary 

B. Overview 

C. Does this action apply to me? 

II. Background 

A. Climate change impacts from GHG emissions 

B. GHG emissions from fossil fuel-fired EGUs 

C. The utility power sector and how its structure is changing 

D. Statutory background 

E. Regulatory and litigation background 

F. Coordination with other rulemakings 

G. Stakeholder input 

III. Proposed Requirements for New Sources 

A. Affected sources 

B. Emission standards 

C. Startup, shutdown, and malfunction requirements 

D. Continuous monitoring requirements 

E. Emissions performance testing requirements 

F. Continuous compliance requirements 

G. Notification, recordkeeping, and reporting requirements 
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IV. Rationale for Reliance on Rational Basis to Regulate GHGs 

from Fossil-fired EGUs 

A. Overview 

B. Climate Change Impacts from GHG Emissions; Amounts of GHGs 

from fossil fuel-fired EGUs 

C. CAA §111 requirements 

D. Interpretation of CAA §111 requirements

E. Rational basis to promulgate standards for GHGs from fossilfired EGUs 

F. Alternative findings of endangerment and significant 

contribution 

G. Comments on the state of the science of climate change 

V. Rationale for Applicability Requirements 

A. Applicability requirements - original proposal and comments 

B. Applicability requirements – today’s proposal 

C. Codification in the Code of Federal Regulations

VI. Legal Requirements for Establishing Emission Standards 

A. Overview 

B. CAA requirements and Court interpretation 

C. Technical feasibility 

D. Factors to consider in determining the “best system” 

E. Nationwide component of factors in determining the “best 

system” 

F. Overall purposes 

G. Chevron framework 

H. Agency discretion 

I. Lack of requirement that standard be able to be met by all 

sources 

VII. Rationale for Emission Standards for New Fossil Fuel-fired 

Utility Boilers and IGCC Units 

A. Overview 

B. Identification of the best system of emission reduction 

C. Determination of the level of the standard 

D. Extent of reductions in CO2 emissions 

E. Technical feasibility 

F. Costs 

G. Promotion of technology 

H. Nationwide, longer-term perspective 

I. Consistency with purposes of CAA section 111 

J. Deference 

K. CCS and BSER in locations where costs are too high to 

implement CCS 

L. Compliance period 

M. Geologic sequestration 

VIII. Rationale for Emission Standards for Natural Gas-fired 

Stationary Combustion Turbines 
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A. Best system of emission reduction 

B. Determination of the standards of performance 

IX. Rationale for Other Requirements 

A. Compliance requirements 

X. Implications for PSD and Title V Programs 

A. Overview 

B. Applicability of tailoring rule thresholds under the PSD 

program 

C. Implications for BACT determinations under PSD 

D. Implications for title V program 

E. Implications for title V fee requirements for GHGs 

XI. Impacts of the Proposed Action 

A. What are the air impacts? 

B. What are the energy impacts? 

C. What are the compliance costs? 

D. How will this proposal contribute to climate change 

protection? 

E. What are the economic and employment impacts? 

F. What are the benefits of the proposed standards? 

XII. Request for Comments 

XIII. Statutory and Executive Order Reviews 

A. Executive Order 12866, Regulatory Planning and Review, and 

Executive Order 13563, Improving Regulation and Regulatory 

Review 

B. Paperwork Reduction Act 

C. Regulatory Flexibility Act as Amended by the Small Business 

Regulatory Enforcement Fairness Act of 1996, 5 U.S.C. 601 et 

seq. 

D. Unfunded Mandates Reform Act of 1995 

E. Executive Order 13132, Federalism 

F. Executive Order 13175, Consultation and Coordination With 

Indian Tribal Governments 

G. Executive Order 13045, Protection of Children From 

Environmental Health Risks and Safety Risks 

H. Executive Order 13211, Actions Concerning Regulations That 

Significantly Affect Energy Supply, Distribution, or Use 

I. National Technology Transfer and Advancement Act 

J. Executive Order 12898, Federal Actions to Address 

Environmental Justice in Minority Populations and Low-Income 

Populations 

I. General Information 

A. Executive summary
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1. Purpose of the Regulatory Action 

On April 13, 2012, under the authority of Clean Air Act 

(CAA) section 111, the EPA proposed a new source performance 

standard to limit emissions of carbon dioxide (CO2) from new 

fossil fuel-fired electric utility generating units, including, 

primarily, coal- and natural gas- fired units (77 FR 22392). 

After consideration of the information provided in more than 2.5 

million comments on the proposal, as well as consideration of 

continuing changes in the electricity sector1, the EPA is issuing 

a new proposal to establish separate standards for fossil fuelfired electric steam generating units (utility boilers and IGCC 

units that use coal, petroleum coke and other fossil fuels) and 

for natural gas-fired stationary combustion turbines reflecting, 

respectively, a determination of the best system of emission 

reduction (BSER) for utility boilers and IGCC units and a BSER 

determination for natural gas-fired stationary combustion 

turbines. Because, in contrast, the April 2012 proposal relied 

on a single standard for all new fossil fuel-fired units, the 

EPA is issuing, as a final action, a notice (published 

separately in today’s Federal Register) that rescinds the 

original proposal, as well as issuing this new proposal. 

2. Summary of the Major Provisions 

This action proposes a separate standard of performance for 

Comment [A1]: This FN appears to be missing 

and/or is duplicative of the next FN, which is also 

labeled FN 1. 

Comment [A2]: What other fossil fuels are 

referred to? It would improve clarity to be more 

specific. 
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utility boilers and IGCC units based on partial implementation 

of carbon capture and storage as the best system of emission 

reduction. The proposed emission limit for those sources is 

1,100 lb CO2/MWh.1

 This action also proposes standards of 

performance for natural gas-fired stationary combustion turbines 

based on modern, efficient natural gas combined cycle technology 

as the best system of emission reduction. The proposed emission 

limits for these sources are 1,000 lb CO2/MWh for larger units 

and 1,100 lb CO2/MWh for smaller units. At this time, the EPA is 

not proposing standards of performance for modified or 

reconstructed sources. 

3. Costs and Benefits 

As explained in the Regulatory Impact Analysis (RIA) for 

this proposed rule, available data indicate that, even in the 

absence of this rule, existing and anticipated economic 

conditions will lead electricity generators to choose new 

generation technologies that would meet the proposed standard 

without installation of additional controls. Therefore, based on 

the analysis presented in Chapter 5 of the RIA, the EPA projects 

that this proposed rule will result in negligible CO2 emission 

changes, quantified benefits, and costs by 2020. These 

 

1

 In this rulemaking, all references to lb CO2/MWh are on a gross 

output basis, unless specifically noted otherwise. 
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projections are in line with utility announcements and EIA 

modeling that indicate that coal units built between now and 

2020 would have CCS, even in the absence of this rule. However, 

for a variety of reasons, some companies may consider coal units 

that the modeling does not anticipate. Therefore, in Chapter 5 

of the RIA, we also present an analysis of the project-level 

costs of a new coal-fired unit with partial CCS alongside the 

project-level costs of a new coal-fired unit without CCS. 

B. Overview 

1. Why is the EPA issuing this proposed rule? 

Greenhouse gas (GHG) pollution threatens the American 

public's health and welfare by contributing to long-lasting 

changes in our climate that can have a range of negative effects 

on human health and the environment. The impacts could include: 

longer, more intense and more frequent heat waves; more intense 

precipitation events and storm surges; less precipitation and 

more prolonged drought in the West and Southwest; more fires and 

insect pest outbreaks in American forests, especially in the 

West; and increased ground level ozone pollution, otherwise 

known as smog, which has been linked to asthma and premature 

death. Health risks from climate change are especially serious 

for children, the elderly and those with heart and respiratory 

problems. 
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The U.S. Supreme Court ruled that GHGs meet the definition 

of “air pollutant” in the Clean Air Act (CAA or Act), and this 

decision clarified that the Act’s authorities and requirements 

apply to GHG emissions. Unlike most other air pollutants, GHGs 

may persist in the atmosphere from decades to millennia, 

depending on the specific greenhouse gas. This special 

characteristic makes it crucial to take initial steps now to 

limit GHG emissions from fossil fuel-fired power plants, 

specifically emissions of carbon dioxide (CO2), since they are 

the nation’s largest sources of carbon pollution. This rule will 

ensure that the next generation of fossil fuel-fired power 

plants in this country will use modern technologies that limit 

harmful carbon pollution. 

On April 13, 2012, the EPA issued a proposed rule to limit 

GHG emissions from fossil fuel-fired power plants by 

establishing a single standard applicable to both natural gasand coal-fired generating units. After consideration of the 

information provided in more than 2.5 million comments on the 

proposal, as well as consideration of continuing changes in the 

electricity sector2

, the EPA is issuing a new proposal to 

 

2

 For example, since April 2012, there has been significant 

progress on two CCS projects (Kemper County and Boundary Dam), 

and they are now both over 75 percent complete. Two other 

projects have continued to make progress toward breaking ground 
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establish separate standards for fossil fuel-fired electric 

steam generating units (utility boilers and IGCC units) and for 

natural gas-fired stationary combustion turbines reflecting, 

respectively, a determination of the best system of emission 

reduction (BSER) for utility boilers and IGCC units that use 

coal, petroleum coke and other fossil fuels, and a BSER 

determination for natural gas-fired stationary combustion 

turbines. Because, in contrast, the April 2012 proposal relied 

on a single standard for all new fossil fuel-fired units, the 

EPA is issuing, as a final action, a notice (published 

separately in today’s Federal Register) that rescinds the 

original proposal, as well as issuing this new proposal.

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

CO2 emissions?

Congress established requirements under section 111 of the 

1970 Clean Air Act to control air pollution from new stationary 

sources through new source performance standards (NSPS). 

Specifically, section 111 requires the EPA to set 

technology-based standards for new stationary sources to 

minimize emissions of air pollution to the environment. For more 

than four decades, the EPA has used its authority under section 

 

(Texas Clean Energy Project and Hydrogen Energy California 

Project). 
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111 to set cost-effective emission standards that ensure newly 

constructed sources use the best performing technologies to 

limit emissions of harmful air pollutants. In this proposal, the 

EPA is following the same well-established, customary 

interpretation and application of the law under section 111 to 

address GHG emissions from new fossil fuel-fired power plants. 

3. What sources should the EPA include as it develops proposed 

standards for GHGs for power plants? 

Before determining the appropriate technologies and levels 

of control that represent BSER for greenhouse gas emissions, the 

EPA must first identify the appropriate sources to control. 

The logical starting point is to consider whether, given 

current trends concerning coal-fired and natural gas-fired power 

plants and the nature of GHGs, the EPA’s current NSPS regulatory 

structure is appropriate. The EPA’s NSPS regulations already 

regulate conventional pollutants from these sources under two 40 

CFR part 60 subparts: subpart Da, electric utility steam 

generating units, which includes both steam electric utility 

boilers and integrated gasified combined cycle (IGCC) units, and 

subpart KKKK, stationary combustion turbines, which includes 

both simple cycle and combined cycle stationary combustion 

turbines. 
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For sources covered under subpart Da, the original proposal 

relied on analysis, primarily undertaken by EIA, indicating 

that, while substantial reliance on coal-fired electricity 

generation would continue in the future, few, if any, new coalfired power plants were likely to be built by 2025. Based in 

part on these results, the EPA concluded that it was appropriate 

to propose a single fuel-neutral standard covering all 

intermediate and baseload units based on the performance of 

recently constructed natural gas combined cycle (NGCC) units. In 

light of developments in the electricity sector since the April 

2012 proposal, and in response to numerous comments on the 

proposal itself, the EPA is changing the approach in today's 

notice and proposing to set separate standards for sources 

covered by this subpart.3

The EPA notes that, since the original proposal, a few 

coal-fired units have reached the advanced stages of 

construction and development, which suggests that proposing a 

separate standard for coal-fired units is appropriate. Since the 

proposal, progress on Southern Company's Kemper County Energy 

Facility, which will deploy IGCC with partial CCS, has 

continued, and the project is now over 75 percent complete. 

 

3

 While the emphasis of EPA’s BSER determination is on coal- and 

petcoke-fired units, the subpart covers all fossil fuel-fired 

EGU boilers and IGCC units, including those burning oil and gas.

Comment [A3]: Without CCS, right? Aren’t a 

few with CCS projected to be built? 

Comment [A4]: This wasn’t the entire basis for 

the previous conclusion that a single standard was 

appropriate. EPA also considered that NGCC was 

available to meet the needs for baseload power and, 

that, even if a coal plant were built, CCS would be 

an option. “Based on these results” here suggests 

that that justification was thinner than it actually 

was. 
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Additionally, two other projects, Summit Power's Texas Clean 

Energy Project (TCEP) and the Hydrogen Energy California Project 

(HECA) – both of which will deploy IGCC with CCS – continue to 

move forward. Continued progress on these projects is consistent 

with the EIA modeling which projects that few, if any, new coalfired EGUs would be built in this decade and that those that are 

built would have CCS.4

 The existence and apparent ongoing 

viability of these IGCC projects with CCS justify a separate 

BSER determination for coal-fired and other solid fossil fuelfired (e.g., petroleum coke) power plants 

In addition to these projects, a number of commenters noted 

that, if natural gas prices increase, there could be greater 

interest in the construction of additional coal-fired generation 

capacity. This, too, is consistent with the EIA analysis, which 

also suggests that, in a limited number of potential scenarios 

generally associated with both significantly higher than 

anticipated electric demand and significantly higher than 

expected natural gas prices, some additional new coal-fired 

generation capacity may be built beyond 2020. It is also 

 

4

 Even in its sensitivity analysis, the EIA does not project any 

additional coal projects beyond its reference case until 2023, 

in a case where power companies assume no emission limitations 

for GHGs, and until 2025 in any sensitivity analysis in which 

there are emission limitations for GHGs.
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consistent with publicly available electric utility Integrated 

Resource Plans (IRPs)5

. 

Many of those IRPs indicated the utilities’ interest in 

developing some amount of generating capacity using other 

intermediate-load and baseload technologies, in addition to new 

NGCC capacity, to meet future demand (albeit, almost always at a 

higher cost than NGCC technology). Only a few utilities’ IRPs 

indicated that new coal-fired generation without CCS was a 

technology option that they were seriously considering to meet 

that demand. Finally, a number of commenters suggested that it 

was important to set standards that preserve options for fuel 

diversity, particularly if natural gas prices exceed projected 

levels. Given this information, the EPA believes that it is 

appropriate to set a separate standard for solid fossil fuelfired EGUs, both to address the small number of coal plants that 

evidence suggests might get built and to set a standard that is 

robust across a full range of possible futures in the energy and 

electricity sectors. 

Utility announcements (about the status of coal projects), 

IRPs, and EIA projections suggest that, by far, the largest 

 

5

 IRPs are planning documents that many Public Utility 

Commissions require utilities to file outlining their plans to 

meet future demand. Many of the IRPs that the EPA has reviewed 

included planning horizons of ten years or more. 
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sources of new fossil fuel-fired electricity generation are 

likely to be natural gas-fired combined cycle (NGCC) units. The 

EPA believes, therefore, that it is also appropriate to set a 

standard for stationary combustion turbines used as EGUs. These 

units are covered under subpart KKKK (stationary combustion 

turbines). 

The EPA also proposes to maintain the definition of EGUs 

under the NSPS that differentiates between EGUs (sources used 

primarily for generating electricity for sale to the grid) and 

non-EGUs (turbines primarily used to generate steam and/or 

electricity for on-site use). That definition defines EGUs as 

units that sell more than 1/3 of their potential electric output 

to the grid. Under this definition, most simple cycle “peaking” 

stationary combustion turbines, which typically sell 

significantly less than 1/3 of their potential electric output 

to the grid, would not be affected by today’s proposal. 

Finally, the EPA is not proposing standards today for one 

conventional coal-fired EGU project which, based on current 

information, appears to be the only such project under 

development that has an active air permit and that has not 

already commenced construction for NSPS purposes. If the EPA 

determines that the project is truly proceeding, it will propose 
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a standard for that source at the time the EPA finalizes today’s 

proposed rule.

4. What is the EPA’s general approach to setting BSER standards 

for new sources under Section 111(b)? 

Section 111(b) requires the EPA to identify the “best 

system of emission reduction....adequately demonstrated” (BSER) 

available to limit pollution. The CAA and subsequent court 

decisions identify the factors for the EPA to consider in a BSER 

determination. For this rulemaking, the following factors are 

key: feasibility, costs, size of reductions and technology. 

Feasibility: The EPA considers whether the system of 

emission reduction is technically feasible. 

Costs: The EPA considers whether the costs of the system 

are not unreasonable. 

Size of reductions: The EPA considers the amount of 

emissions reductions that the system would generate. 

Technology: The EPA considers whether the system promotes 

the implementation and further development of technology. 

After considering these four factors, we propose to find 

partial implementation of carbon capture and storage (CCS) 

technology to be the BSER for new affected fossil fuel-fired 

boilers and IGCC units (subpart Da sources) and modern, 

efficient NGCC units to be the BSER for new affected combustion 

Comment [A5]: It would improve clarity by 

adding a footnote with references and a summary of 

the court decisions. 

Comment [A6]: suggest to change “find” to 

“define,” or revise the sentence to “..., we propose 

that partial implementation of carbon capture and 

storage (CCS) technology to be the BSER...” 
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turbines (subpart KKKK sources). The foundations for these 

determinations are described in sections VII and VIII.

5. What is BSER for fossil fuel-fired boilers and IGCC units? 

Power generated from the combustion or gasification of coal 

emits more CO2 than power generated from the combustion of 

natural gas or by other means, such as non-emitting solar or 

wind. If any new coal-fired unit is built, its CO2 emissions 

would be significantly greater than a comparably sized NGCC 

unit. Thus, it is important to set a standard for any new coal 

plant that might be built. 

The three alternatives the EPA considered in the BSER 

analysis for new fossil fuel-fired utility boilers and IGCC 

units are: (1) highly efficient new generation that does not 

include CCS technology, (2) new generation with “full capture” 

CCS and (3) new generation with “partial capture” CCS. 

Generation technologies representing enhancements in 

operational efficiency (e.g., supercritical or ultrasupercritical coal-fired boilers or IGCC units) are clearly 

technically feasible and present little or no incremental cost 

compared to the types of technologies companies weighing new 

coal-fired generation without CCS are considering. However, they 

do not provide meaningful reductions in CO2 emissions from new 

sources. Efficiency-improvement technologies alone result in 

Comment [A7]: Is non-emitting completely 

accurate? Suggest rephrasing as low emitting. 

Comment [A8]: It could be helpful to provide 

numeric magnitude of differences, such as adding 

“...significantly greater (e.g., X%-X%) than a 

comparable sized NGCC unit.” 
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only very small reductions in CO2 emissions, especially in 

contrast to those achieved by the application of CCS. 

Determining that these high-efficiency generating technologies 

represent the BSER for CO2 emissions from coal-fired generation 

would fail to promote the development and deployment of CO2

pollution-reduction technology from power plants. In fact, a 

finding that this efficiency-enhancing technology alone, as 

opposed to CCS, is the BSER for CO2 emissions from coal-fired 

generation likely would inhibit the development of technology 

that could reduce CO2 emissions significantly, thus defeating one 

of the purposes of the CAA's NSPS provisions. For example, 

during its pilot-scale CCS demonstration at the Mountaineer 

Plant in New Haven, WV, American Electric Power (AEP) 

placedannounced in [insert year] that it was placinged on hold 

its plans to scale-up the CCS system, citing the uncertain 

status of U.S. climate policy as a contributor to its decision. 

Reflecting An assessment of the tThe technical feasibility 

and availability of CCS, indicates that at least half of the 

coal-fired power plants that are currently under development are 

designed to use some type of CCS. In most cases, the projects 

will sell or use the captured CO2 as to generate additional 

revenue. These projects include: 

Comment [A9]: Again, would be helpful to give 

numeric examples, such as the range of percentage 

reductions in CO2 emissions. 

Comment [A10]: Suggested edits to enhance 

clarity. 

Comment [A11]: Perhaps “determination” is 

more appropriate. 

Comment [A12]: Perhaps change to “a key 

contributing factor”? 

Comment [A13]: Does EPA know if all of the 

planned projects intend to generate revenues from 

captured CO2, which seems to be what a company 

would want to do to improve the economics of a 

CCS project? Can EPA explain the difference 

between “sell” and “use”? 
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Southern Company’s Kemper County Energy Facility, a 582 MW 

IGCC power plant that is currently under construction in 

Kemper County, Mississippi. The plant will include, with 

some financial assistance from DOE, a CCS system designed 

to capture approximately 65 percent of the produced CO2. 

Texas Clean Energy Project (TCEP), an IGCC plant near 

Odessa, Texas, that is under development by the Summit 

Power Group, Inc. (Summit). TCEP is a 400 MW IGCC plant 

that expects to capture approximately 90 percent of the 

produced CO2. 

Hydrogen Energy California, LLC (HECA), is proposing to 

build a plant similar to TCEP in western Kern County, 

California. The HECA plant is an IGCC plant fueled by coal 

and petroleum coke that will produce 300 MW of power and 

will capture CO2 for use in enhanced oil recovery (EOR) 

operations. They expect to capture approximately 90 percent 

of the produced CO2. 

The above examples suggest that project developers who are 

incorporating CCS generally considered two variants: either a 

partial CCS system, or a full CCS system. Therefore, the EPA 

considered both “full capture” and “partial capture” CCS 

technologies. 
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Coal plants implementing “full capture” CCS plan to achieve 

large reductions in CO2 pollution - usually 90 percent or more, 

though it is not clear whether the units being developed today 

will be able to achieve full capture at the outset..

In assessing whether the cost of a certain option is not 

unreasonable, the EPA first considered the appropriate frame of 

referencereferenc. Power companies often choose the lowest cost 

form of generation when determining what type of new generation 

to build. Based both on the EIA modeling and utility IRPs, there 

appears to be a general acceptance that the lowest cost form of 

new power generation is NGCC. 

Many states find value in coal investments and have 

policies and incentives to encourage coal energy generation. 

Utility IRPs (as well as comments on the April 2012 proposal) 

suggest that many companies also find value in other factors, 

such as fuel diversity, and are often willing to pay a premium 

for it. Utility IRPs suggest that a range of technologies can 

meet this preference, including coal without CCS, coal with CCS 

and nuclear. Biomass-fired power generation and geothermal power 

generation are other technologies that are dispatchable and that 

could potentially meet this objective. These technologies all 

cost significantly more than natural gas-fired generation, which 

ranges from $52/MWh to $86/MWh, depending upon assumptions about 

Comment [A14]: This statement should further 

clarify whether these facilities will, at a minimum, 

achieve “partial capture” at the outset. 

Comment [A15]: Is EPA confident on this 

statement? Will this be read as EPA casting doubt 

on the viability of the project TCEP or HECA 

project? 

Comment [A16]: Suggested edit to enhance 

clarity. 

Comment [A17]: It would be helpful to add 

some language to clarify whether these technologies 

are comparable, i.e., are these technologies used to 

serve base-load and intermediate loads, and would 

they have comparable generation capacity? 

Comment [A18]: Are these LCOE estimates? 

Should probably specify. 
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natural gas prices. In assessing whether the cost of coal with 

CCS would have an unreasonable impact on the cost of power 

generation, the EPA believes it is appropriate to compare coal 

with CCS to this range of non-natural gas-fired electricity 

generation options. Based on data from the EIA and the DOE 

National Energy and Technology Laboratory (NETL), the EPA 

believes that the cost of technologies other than coal with CCS 

and NGCC range from $80/MWh to $130/MWh. These include nuclear 

at $103/MWh to $114/MWh, biomass at $97/MWh to $130/MWh, and 

geothermal at $80/MWh to $99/MWh.

The cost of “full capture” CCS mitlitgates against 

determining that it is the BSER for CO2 emissions for coal-fired 

power plants. The EPA projects the levelized cost of electricity 

of generation technologies with full capture to be in the range 

of $136/MWh to $147/MWh. Because ”full capture” CCS costs 

without EOR are significantly above the price range of potential 

alternative generation options, the EPA believes that full 

capture CCS does not meet the cost criterion of BSER. 

Finally, the EPA considered whether implementation of 

“partial capture” CCS should be proposed to be BSER for new 

fossil fuel-fired utility boilers and IGCC units. 

Partial capture CCS has been implemented successfully in a 

number of facilities over many years. The Great Plains Synfuels 

Comment [A19]: Are these “levelized” costs? 

Comment [A20]: Are these LCOE estimates? 

Should probably specify. 

Comment [A21]: Without EOR, right? Should 

specify in this sentence. 

Comment [A22]: Could EPA please provide 

estimated levelized costs for full capture project with 

EOR revenue and compare with other forms of 

generation? As stated above, CCS+EOR appears to 

be most likely scenario, an assessment of the 

economics of CCS+EOR scenario is more relevant. 

Comment [A23]: Are there any international 

facilities that can be referenced here? 
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Facility6

 is a coal gasification facility that has captured at 

least 50 percent of its produced CO2 for use in enhanced oil 

recovery (EOR) operations since 2000. Projects such as AEP 

Mountaineer have successfully demonstrated the performance of 

partial capture CCS on a significant portion of their exhaust 

stream. The Southern Company Kemper County Energy Facility will 

use partial CCS to capture approximately 65 percent of the 

produced CO2 for use in nearby EOR operations. The facility is 

now more than 75 percent complete and is expecting to begin 

operation in 2014. 

When considered against the range of costs that would be 

incurred by projects deploying non-natural gas-fired electricity 

generation, the implementation costs of partial CCS are, 

clearly, not unreasonable. The EPA analysis shows that the costs 

of partial CCS are comparable to costs of other non-NGCC 

generation. The EPA projects levelized costs of electricity 

generation ranging from $92/MWh to $110/MWh, depending upon 

assumptions about technology choices and the amount, if any, of 

revenue from sale of CO2 for EOR. This range compares to 

levelized costs in a range of $80/MWh to $130/MWh for various 

 

6

 While this facility is not an EGU, it has significant 

similarities to a coal gasification combined cycle EGU, and the 

implementation of the partial CCS technology would be similar 

enough for comparison.

Comment [A24]: This conclusion would fit more 

appropriately at the end of the paragraph. Without 

reading the LCOE information, it is not “clearly, not 

unreasonable” 
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forms of other non-natural gas-fired electricity generation. 

These include nuclear at $103/MWh to $114/MWh, biomass at 

$97/MWh to $130/MWh, and geothermal at $80/MWh to $99/MWh.

The projects in development for new coal-fired generation 

are few in number, and most would already meet an emission limit 

based on implementation of partial CCS. As a result, a standard 

based on partial CCS would not have a significant impact on 

nationwide energy prices. Moreover, the fact that IGCC 

developers could meet the requirements of the standard through 

the use of a more conventional turbine (syngas turbine, rather 

than a more advanced hydrogen turbine) reinforces both the 

technical feasibility and cost basis of the EPA’s proposal to 

determine that CCS with partial capture is the BSER. 

Partial CCS (designed to meet an emission standard of 1,100 

lb CO2/MWh) would also achieve significant emission reductions, 

emitting on the order of 30 to 50 percent less CO2 than a coalfired unit without CCS. Finally, a partial CCS requirement 

clearly promotes CCS technologies, and does so as much as a 

standard based on a full capture CCS requirement would. 

After conducting a BSER analysis of the three options 

described above, the EPA proposes that new fossil fuel-fired 

utility boilers and IGCC units implementing partial CCS best 

meets the requirements for BSER. It ensures that any new fossil 

Comment [A25]: Suggest moving this 

information above (see insert) to improve clarity. 

Formatted: Subscript
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fuel-fired utility boiler or IGCC unit will achieve meaningful 

emission reductions in CO2, and it will also encourage greater 

use, development, and refinement of CCS technologies. CCS 

technology has been adequately demonstrated, and its 

implementation costs are reasonable. Therefore, the EPA is 

basing the standards for new fossil fuel-fired utility boilers 

and IGCC units on partial carbon capture and storage (CCS) 

technology operating to a level of 1,100 lb CO2/MWh. 

6. What is BSER for fossil fuel-fired stationary combustion 

turbines? 

We considered two alternatives in evaluating the BSER for 

new fossil fuel-fired stationary combustion turbines: (1) 

modern, efficient NGCC units and (2) modern, efficient NGCC 

units with CCS. 

NGCC units are the most common type of new fossil fuelfired units being planned and built today. The technology is in 

wide use. Nearly all new fossil fuel-fired EGUs being 

constructed today are using this advanced, efficient system for 

generating intermediate and baseload power. Importantly, NGCC is 

an inherently lower CO2-emitting technology. Almost every natural 

gas-fired stationary combined cycle unit built in the U.S. in 

the last five years emits approximately 50 percent less CO2 per 

MWh than a typical new coal-fired plant of the same size. The 
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design is technically feasible, and evidence shows that NGCC 

units are currently the lowest-cost, most efficient option for 

new fossil fuel-fired power generation. 

By contrast, NGCC with CCS is not a configuration that is 

widely being planned and built today. The EPA considered whether 

NGCC with CCS could be identified as the best system of emission 

reductions adequately demonstrated for new stationary combustion 

turbines, and we decided that it could not be identified for 

several reasons. At this time, CCS has not been implemented for 

NGCC units, and we believe there is insufficient information to 

make a determination regarding the technical feasibility of 

implementing CCS at these types of units. The EPA is aware of 

only one NGCC unit that has implemented CCS on a very small 

portion of its exhaust stream. The EPA is not aware of any 

demonstrations of NGCC units implementing CCS technology that 

would justify setting a national standard. Further, the EPA does 

not have sufficient information on the prospects of transferring 

the coal-based experience with CCS to NGCC units. In fact, CCS 

technology has primarily been applied to gas streams that have a 

relatively high to very high concentration of CO2 (such as that 

from a coal combustion or coal gasification unit). The 

concentration of CO2 in the flue gas stream of a coal combustion 

unit is normally about four times higher than the concentration 

Comment [A26]: 

Comment [A27]: Is it a question of technical 

feasibility, as in, whether it is technically feasible to 

implement CCS with NGCC, or is it a question of 

overall likelihood that CCS would be implemented 

with NGCC. Are there are technical constraints to 

actually using CCS in the NGCC context? Or, are 

there financial and efficiency drivers involved? 
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of CO2 in a natural gas-fired unit. Natural gas-fired stationary 

combustion turbines also operate differently from coal-fired 

boilers and IGCC units of similar size. The NGCC units are more 

easily cycled (i.e., ramped up and down as power demands 

increase and decrease). This cyclical operation, combined with 

the already low concentration of CO2 in the flue gas stream, lead 

to uncertainty about how technically feasible CCS technology is 

for NGCC units absent further information. 

After considering both technology options, the EPA is 

proposing to find modern, efficient NGCC technology to be the 

BSER for stationary combustion turbines, and we are basing the 

proposed standards on the performance of recently constructed 

NGCC units. The EPA is proposing that larger units be required 

to meet a standard of 1,000 lb CO2/MWh and that smaller units 

(typically slightly less efficient, as noted in comments on the 

original proposal) be required to meet a standard of 1,100 lb 

CO2/MWh. 

7. What is the organization and approach for the proposal? 

 This action presents the EPA’s proposed approach for 

setting standards of performance for new affected fossil fuelfired electric utility steam generating units (utility boilers) 

and stationary combustion turbines. The rationale for regulating 

GHG emissions from the utility power sector, including related 

Comment [A28]: Are there references to support 

these statements? 
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regulatory and litigation background and relationship to other 

rulemakings, is presented below in section II. The specific 

proposed requirements for new sources are described in detail in 

section III. The rationale for reliance on a rational basis to 

regulate GHG emissions from fossil fuel-fired EGUs is presented 

in section IV, followed by the rationale for applicability 

requirements in section V. The legal requirements for 

establishing emission standards are discussed in detail in 

section VI. Sections VII and VIII describe the rationale for 

each of the proposed emission standards, including an 

explanation of the determination of BSER for new fossil fuelfired utility boilers and IGCC units and for natural gas-fired 

stationary combustion turbines, respectively. Rationale for 

other proposed requirements is discussed in section IX. 

Implications for PSD and title V programs are described in 

section X, and impacts of the proposed action are described in 

section XI. In section XII, the agency specifically requests 

comments on the proposal. A discussion of statutory and 

executive order reviews is provided in section XIII. Also 

published today in the Federal Register is the notice rescinding 

the original April 13, 2012 proposal. 

Today’s proposal outlines an approach for setting standards 

of performance for emissions of carbon dioxide for new affected 

Comment [A29]: Spell out when it first appears. 
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fossil fuel-fired electric utility steam generating units 

(utility boilers) and stationary combustion turbines. 

C. Does this action apply to me?

The entities potentially affected by the proposed standards 

are shown in Table 1 below. 

Table 1. Potentially Affected Entitiesa

 

Category NAICS 

Code 

Examples of Potentially Affected 

Entities 

Industry 

 

221112 

 

Fossil fuel electric power generating 

units.

Federal 

Government 

 

221112b

 

Fossil fuel electric power generating 

units owned by the federal government.

State/Local 

Government 

 

221112b

 

Fossil fuel electric power generating 

units owned by municipalities. 

Tribal 

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

a IncludeIncludes NAICS categories for source categories that own 

and operate electric power generating units (including boilers 

and stationary combined cycle combustion turbines). 

b

 Federal, state, or local government-owned and operated 

establishments are classified according to the activity in which 

they are engaged. 

This table is not intended to be exhaustive, but rather to 

provide a guide for readers regarding entities likely to be 

affected by this proposed action. To determine whether your 

facility, company, business, organization, etc., would be 
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regulated by this proposed action, you should examine the 

applicability criteria in 40 CFR 60.1. If you have any questions 

regarding the applicability of this action to a particular 

entity, consult either the air permitting authority for the 

entity or your EPA regional representative as listed in 40 CFR 

60.4 or 40 CFR 63.13 (General Provisions). 

II. Background 

In this section we discuss climate change impacts from GHG 

emissions, both on public health and public welfare, and the 

science behind the agency’s conclusions. We present information 

about GHG emissions from fossil-fuel fired EGUs, and we describe 

the utility power sector and its changing structure. We then 

provide the statutory, regulatory, and litigation background for 

this proposed rule. We close this section by discussing how this 

proposed rule coordinates with other rulemakings and describing 

actions to obtain stakeholder input on this topic and the 

original proposed rule. 

A. Climate change impacts from GHG emissions

In 2009, the EPA Administrator issued the document we refer 

to as the Endangerment Finding under CAA section 202(a)(1).7

 In 

the Endangerment Finding, which focused on public health and 

 

7

 “Endangerment and Cause or Contribute Findings for Greenhouse 

Gases Under Section 292(a) of the Clean Air Act,” 74 Fed. Reg. 

66,496 (Dec. 15, 2009) (“Endangerment Finding”). 
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public welfare impacts within the United States, the 

Administrator found that elevated concentrations of GHGs in the 

atmosphere may reasonably be anticipated to endanger public 

health and welfare of current and future generations. We 

summarize these adverse effects on public health and welfare 

briefly here and in more detail in the RIA. 

1. Public health impacts detailed in the 2009 Endangerment 

Finding 

Anthropogenic emissions of GHGs and consequent climate 

change threaten public health in multiple aspects. By raising 

average temperatures, climate change increases the likelihood of 

heat waves, which are associated with increased deaths and 

illnesses. While climate change also leads to reductions in 

cold-related mortality, evidence indicates that the increases in 

heat mortality will be larger than the decreases in cold 

mortality. Climate change is expected to increase ozone 

pollution over broad areas of the country, including large 

population areas with already unhealthy surface ozone levels, 

and thereby increase morbidity and mortality. Other public 

health threats also stem from increases in intensity or 

frequency of extreme weather associated with climate change, 

such as increased hurricane intensity, increased frequency of 

intense storms and heavy precipitation. Increased coastal storms 
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and storm surges due to rising sea levels are expected to cause 

increased drownings and other health impacts. Children, the 

elderly, and the poor are among the most vulnerable to these 

climate-related health effects. 

2. Public welfare impacts detailed in the 2009 Endangerment 

Finding 

Anthropogenic emissions of GHGs and consequent climate 

change also threaten public welfare in multiple aspects. Climate 

changes is expected to place large areas of the country at 

serious risk of reduced water supplies, increased water 

pollution, and increased occurrence of extreme events such as 

floods and droughts. Coastal areas are expected to face 

increased risks from storm and flooding damage to property, as 

well as adverse impacts from sea level rise, such as land loss 

due to inundation, erosion, wetland submergence and habitat 

loss. Climate change is expected to result in an increase in 

peak electricity demand, and extreme weather from climate change 

threatens energy, transportation, and water resource 

infrastructure. Climate change may exacerbate ongoing 

environmental pressures in certain settlements, particularly in 

Alaskan indigenous communities. Climate change also is very 

likely to fundamentally rearrange U.S. ecosystems over the 21st

century. Though some benefits may balance adverse effects on 
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agriculture and forestry in the next few decades, the body of 

evidence points towards increasing risks of net adverse impacts 

on U.S. food production, agriculture and forest productivity as 

temperatures continue to rise. These impacts are global and may 

exacerbate problems outside the U.S. that raise humanitarian, 

trade, and national security issues for the U.S. 

3. The science upon which the Agency relies 

The EPA received comments in response to the April 2012 

proposed NSPS rule (77 FR 22392) that addressed the scientific 

underpinnings of the EPA’s 2009 Endangerment Finding and hence 

the proposed rule. The EPA carefully reviewed all of those 

comments. It is important to place these comments in the context 

of the history and associated voluminous record on this subject 

that has been compiled over the last few years, including: 1) 

the process by which the Administrator reached the Endangerment 

Finding in 2009; 2) the EPA’s response in 2010 to ten 

administrative petitions for reconsideration of the Endangerment 

Finding (the Reconsideration Denial)8

; and 3) the decision by the 

United States Court of Appeals for the District of Columbia 

 

8

 “EPA’s Denial of the Petitions to Reconsider the Endangerment 

and Cause or Contribute Findings for Greenhouse Gases Under 

Section 202(a) of the Clean Air Act, 75 Fed. Reg. 49,557 (Aug. 

13, 2010) (“Reconsideration Denial”). 
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Circuit (the D.C. Circuit or the Court) in 2012 to uphold the 

Endangerment Finding and the Reconsideration Denial.9,10

As outlined in Section VIII.A. of the 2009 Endangerment 

Finding, the EPA’s approach to providing the technical and 

scientific information to inform the Administrator’s judgment 

regarding the question of whether GHGs endanger public health 

and welfare was to rely primarily upon the recent, major 

assessments by the U.S. Global Change Research Program (USGCRP), 

the Intergovernmental Panel on Climate Change (IPCC), and the 

National Research Council (NRC) of the National Academies. These 

assessments addressed the scientific issues that the EPA was 

required to examine, were comprehensive in their coverage of the 

GHG and climate change issues, and underwent rigorous and 

exacting peer review by the expert community, as well as 

rigorous levels of U.S. government review. The EPA received 

thousands of comments on the proposed Endangerment Finding and 

responded to them in depth in an 11-volume Response to Comments 

(RTC) document.11 While the EPA gave careful consideration to all 

 

9 Coalition for Responsible Regulation, Inc. v. EPA, 684 F.3d 102 

(D.C. Cir. 2012), rehearing and rehearing en banc den. ________ 

(“CRR”). 10 We discuss litigation history involving this rulemaking in 

more detail later in this section. 

11 “Endangerment and Cause or Contribute Findings for Greenhouse 

Gases under Section 202(a) of the Clean Air Act: EPA's Response 
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of the scientific and technical information received, the agency 

placed less weight on the much smaller number of individual 

studies that were not considered or reflected in the major 

assessments; often these studies were published after the 

submission deadline for those larger assessments. Primary 

reliance on the major scientific assessments provided the EPA 

greater assurance that it was basing its judgment on the best 

available, well-vetted science that reflected the consensus of 

the climate science community. The EPA reviewed individual 

studies not incorporated in the assessment literature largely to 

see if they would lead the EPA to change its interpretation of, 

or place less weight on, the major findings reflected in the 

assessment reports. From its review of individual studies 

submitted by commenters, the EPA concluded that these studies 

did not change the various conclusions and judgments the EPA 

drew from the more comprehensive assessment reports. The major 

findings of the USGCRP, IPCC, and NRC assessments supported the 

EPA’s determination that GHGs threaten the public health and 

welfare of current and future generations. The EPA presented 

this scientific support at length in the Endangerment Finding, 

 

to Public Comments,” 

http://www.epa.gov/climatechange/endangerment/#comments 

(“Response to Comments” or “RTC”).
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in its Technical Support Document (which summarized the findings 

of USGCRP, IPCC and NRC)12 and in the RTC. 

The EPA then reviewed ten administrative petitions for 

reconsideration of the Endangerment Finding in 2010. In the 

Reconsideration Denial, the Administrator denied those petitions 

on the basis that the Petitioners failed to provide substantial 

support for the argument that the EPA should revise the 

Endangerment Finding and therefore their objections were not of 

“central relevance” to the Finding. The EPA prepared an 

accompanying three-volume Response to Petitions (RTP) document 

to provide additional information, often more technical in 

nature, in response to the arguments, claims, and assertions by 

the petitioners to reconsider the Endangerment Finding.13 

The 2009 Endangerment Finding and the 2010 Reconsideration 

Denial were challenged in a lawsuit before the D.C. Circuit. On 

June 26, 2012, the Court upheld the Endangerment Finding and the 

Reconsideration Denial, ruling that the Finding (including the 

Reconsideration Denial) was not arbitrary or capricious, was 

consistent with the U.S. Supreme Court’s decision in 

 

12 “Technical Support Document for Endangerment and Cause or 

Contribute findings for Greenhouse Gases under Section 202(s) of 

the Clean Air Act (Dec. 7, 2009), 

http://www.epa.gov/climatechange/Downloads/endangerment/Endanger

ment_TSD.pdf (TSD). 

13 http://www.epa.gov/climatechange/endangerment/petitions.html 
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Massachusetts v. EPA, which granted to the EPA the authority to 

regulate GHGs,14 and was adequately supported by the 

administrative record.15 The Court found that the EPA had based 

its decision on “substantial scientific evidence” and noted that 

the EPA’s reliance on assessments was consistent with the 

methods decision-makers often use to make a science-based 

judgment.16 The Court also agreed with the EPA that the 

Petitioners had “not provided substantial support for their 

argument that the Endangerment Finding should be revised.”17 

Moreover, the Court supported the EPA’s reliance on the major 

scientific assessment reports conducted by USGCRP, IPCC, and NRC 

and found that: 

The EPA evaluated the processes used to develop 

the various assessment reports, reviewed their 

contents, and considered the depth of the scientific 

consensus the reports represented. Based on these 

evaluations, the EPA determined the assessments 

represented the best source material to use in 

deciding whether GHG emissions may be reasonably 

anticipated to endanger public health or welfare.18

As the Court stated – 

It makes no difference that much of the 

scientific evidence in large part consisted of 

‘syntheses’ of individual studies and research. Even 

 

14 549 U.S. 497 (2007). 15 CRR, 684 F.3d at 117-27. 16 Id. at 121. 17 Id. at 125. 18 Id. at 120. 
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individual studies and research papers often 

synthesize past work in an area and then build upon 

it. This is how science works. The EPA is not required 

to re-prove the existence of the atom every time it 

approaches a scientific question.19

 

In the context of this extensive record and the recent 

affirmation of the Endangerment Finding by the Court, the EPA 

considered all of the submitted comments and reports for the 

April 2012 proposed NSPS rule. As it did in the Endangerment 

Finding, the EPA gave careful consideration to all of the 

scientific and technical comments and information in the record. 

The major peer-reviewed scientific assessments, however, 

continue to be the primary scientific and technical basis for 

the Administrator’s judgment regarding the threats to public 

health and welfare posed by GHGs. 

Commenters submitted two major peer-reviewed scientific 

assessments released after the administrative record concerning 

the Endangerment Finding closed after the EPA’s 2010 

Reconsideration Denial: the IPCC’s 2012 “Special Report on 

Managing the Risks of Extreme Events and Disasters to Advance 

Climate Change Adaptation” (SREX) and the NRC’s 2011 “Report on 

Climate Stabilization Targets: Emissions, Concentrations, and 

 

19 Id. at 120. 
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Impacts over Decades to Millennia” (Climate Stabilization 

Targets). 

According to the IPCC in the SREX, “A changing climate 

leads to changes in the frequency, intensity, spatial extent, 

duration, and timing of extreme weather and climate events, and 

can result in unprecedented extreme weather and climate 

events.20” The SREX documents observational evidence of changes 

in some weather and climate extremes that have occurred globally 

since 1950. The assessment also provides evidence regarding the 

cause of some of these changes to elevated concentrations of 

GHGs, including warming of extreme daily temperatures, 

intensified extreme precipitation events, and increases in 

extreme coastal high water levels due to rising sea level. The 

SREX projects further increases in some extreme weather and 

climate events during the 21st century. Combined with increasing 

vulnerability and exposure of populations and assets, changes in 

extreme weather and climate events have consequences for 

disaster risk, with particular impacts on the water, agriculture 

and food security and health sectors. 

In the Climate Stabilization Targets assessment, the NRC 

states: 

 

20 SREX, p. 7. 
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Emissions of carbon dioxide from the burning of 

fossil fuels have ushered in a new epoch where human 

activities will largely determine the evolution of 

Earth’s climate. Because carbon dioxide in the 

atmosphere is long lived, it can effectively lock 

Earth and future generations into a range of impacts, 

some of which could become very severe.21 

The assessment concludes that carbon dioxide emissions will 

alter the atmosphere’s composition and therefore the climate for 

thousands of years; and attempts to quantify the results of 

stabilizing GHG concentrations at different levels. The report 

also projects the occurrence of several specific climate change 

impacts, finding warming could lead to increases in heavy 

rainfall and decreases in crop yields and Arctic sea ice extent, 

along with other significant changes in precipitation and stream 

flow. For an increase in global average temperature of 1 to 2 oC 

above pre-industrial levels, the assessment found that the area 

burnt by wildfires in western North America will likely more 

than double and coral bleaching and erosion will increase due 

both to warming and ocean acidification. An increase of 3 oC 

will lead to a sea level rise of 0.5 to 1 meter by 2100. With an 

increase of 4 oC, the average summer in the United States would 

be as warm as the warmest summers of the past century. The 

assessment notes that although many important aspects of climate 

 

21 Climate Stabilization Targets, p. 3. 
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change are difficult to quantify, the risk of adverse impacts is 

likely to increase with increasing temperature, and the risk of 

surprises can be expected to increase with the duration and 

magnitude of the warming. 

Several other National Academy assessments regarding 

climate have also been released recently. The EPA has reviewed 

these assessments and finds that in general, the improved 

understanding of the climate system they and the two assessments 

described above present strengthens the case that GHGs are 

endangering public health and welfare. Three of the new NRC 

assessments provide estimates of projected global sea level rise 

that are twice as large or more than the rise estimated in a 

2007 IPCC assessment of between 0.18 and 0.59 meters by the end 

of the century, relative to 1990 (and noting that including 

poorly understood ice sheet processes would likely increase 

those projections).22 While these three NRC assessments continue 

to recognize and characterize the uncertainty inherent in 

accounting for ice sheet processes, these revised estimates 

strongly support and strengthen the existing finding that GHGs 

are reasonably anticipated to endanger public health and 

 

22 Climate Stabilization Targets; “National Security Implications 

for U.S. Naval Forces” (2011) (National Security Implications); 

“Sea Level Rise for the Coasts of California, Oregon, and 

Washington: Past, Present, and Future” (2012) (Sea Level Rise). 
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welfare. Other key findings of the recent assessments are 

described briefly below: 

One of these assessments projects a global sea level rise 

of 0.5 to 1.4 meters by 2100, which is sufficient to lead to 

rising relative sea level even in the northern states.23 Another

assessment considers potential impacts of sea level rise and 

suggests that “the Department of the Navy should expect roughly 

0.4 to 2 meters global average sea-level rise by 2100.24 This 

assessment also recommends preparing for increased needs for 

humanitarian aid, responses to climate change in geopolitical 

hotspots including possible mass migrations and addressing 

changing security needs in the Arctic as sea ice retreats. A 

third NRC assessment found that it would be “prudent for 

security analysts to expect climate surprises in the coming 

decade . . . and for them to become progressively more serious 

and more frequent thereafter[.]”25

Another NRC assessment finds that “the magnitude and rate 

of the present greenhouse gas increase place the climate system 

in what could be one of the most severe increases in radiative 

 

23 Sea Level Rise, p. XX. 24 National Security Implications, p. 9. 25 “Climate and Social Stress: Implications for Security 

Analysis” (2012), p.3. 
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forcing of the global climate system in Earth history.”26) This 

assessment finds that CO2 concentrations by the end of the 

century will likely exceed levels not present in the 30 million 

years since the formation of the Antarctic and Greenland Ice 

Sheets.27 The assessment examines evidence from past climatic 

changes and concludes that the climate could be more sensitive 

to greenhouse gases, the tropical surface temperatures less well 

regulated, sea level rise higher, and the oceans more anoxic 

than current expectations. The report draws potential parallels 

with non-linear events such as the Paleo-Eocene Thermal Maximum, 

a rapid global warming event about 55 million years ago 

associated with mass extinctions and other disruptions. The 

assessment notes that acidification and warming caused by GHG 

increases similar to the changes expected over the next hundred 

years likely caused up to four of the five major coral reef 

crises of the past 500 million years. 

Similarly, another NRC assessment finds that “[t]he 

chemistry of the ocean is changing at an unprecedented rate and 

magnitude due to anthropogenic carbon dioxide emissions; the 

rate of change exceeds any known to have occurred for at least 

 

26 “Understanding Earth’s Deep Past: Lessons for Our Climate 

Future” (2011), p.138. 

27 ??? 

Comment [A30]: Omit ending parenthesis 
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the past hundreds of thousands of years.”28 The assessment notes 

that the full range of consequences is still unknown, but the 

risks “threaten coral reefs, fisheries, protected species, and 

other natural resources of value to society” (p. 5). 

Comments were submitted in support of the Endangerment 

Finding and providing additional documentation showing that 

climate change is a threat to public health and welfare. 

Commenters provided several individual studies and documentation 

of observed or projected climate changes of local importance or 

concern to commenters. The EPA appreciates these comments, but 

as previously stated, we place lesser weight on individual 

studies than on major scientific assessments. Local observed 

changes must be assessed in the context of the broader 

scientific picture, as it is more difficult to draw robust 

conclusions regarding climate change over short time scales and 

in small geographic regions. 

The EPA plans to continue relying on the major assessments 

by the USGCRP, the IPCC, and the NRC. Studies from these bodies 

address the scientific issues that the Administrator must 

examine, they represent the current state of knowledge on the 

key elements for the endangerment analysis, comprehensively 

 

28 “Ocean Acidification: A National Strategy to Meet the 

Challenges of a Changing Ocean” (2010), p. 5. 
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cover and synthesize thousands of individual studies to obtain 

the majority conclusions from the body of scientific literature 

and undergo a rigorous and exacting standard of review by the 

peer expert community and U.S. government. 

Several commenters argued that the Endangerment Finding 

should be reconsidered or overturned based on those commenters’ 

reviews of specific climate science literature, including 

publications that have appeared since the EPA’s 2010 

Reconsideration Denial. Some commenters presented their own 

compilations of individual studies and other documents to 

support their assertions that climate change will have 

beneficial effects in many cases and that climate impacts will 

not be as severe or adverse as the EPA and a certain USGCRP 2009 

report have stated. Some commenters also concluded that U.S. 

society will easily adapt to climate change and that it 

therefore does not threaten public health and welfare, and some 

commenters questioned the Endangerment Finding based on a 2011 

EPA Inspector General’s report. 

The EPA reviewed the submitted information and found that 

overall, the EPA had addressed the commenters’ critiques of the 

rule’s scientific basis were addressed in the EPA’s response to 

comments for the 2009 Endangerment Finding, the EPA’s responses 

in the 2010 Reconsideration Denial, or the D.C. CircuitCircuit’s
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in its 2012 decision to upholdupholding the EPA’s 2009 

Endangerment Finding. The EPA nonetheless carefully reviewed 

these comments and associated documents and found that nothing 

in them would change the conclusions and that the EPA reached in 

the Endangerment Finding. These recent publications submitted by 

commenters, and any new issues that are extracted from them, do 

not undermine either the significant body of scientific evidence 

that has accumulated over the years or the conclusions presented 

in the substantial peer-reviewed assessments of the USGCRP, NRC, 

and IPCC. 

One commenter submitted e-mails between climate change 

researchers from the period 1999 to 2009 that were 

surreptitiously obtained from a University of East Anglia server 

in 2009 and publicly released in 2011. According to the 

commenter, these e-mails showed that the climatologists 

distorted their research results to prove that climate change 

causes adverse effects. The EPA reviewed these emails and found 

that they raised no issues that Petitioners had not already 

raised concerning other emails from the same incident, released 

in 2009. The commenter’s unsubstantiated assumptions and 

subjective assertions regarding what the e-mails purport to show 

about the state of climate change science is not adequate 
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evidence to challenge the voluminous and well-documented body of 

science that underpins the Administrator’s Endangerment Finding. 

Some commenters argued for reconsideration based on 

uncertainty regarding climate science. However, the EPA made the 

decision to find endangerment with full and explicit recognition 

of the uncertainty involved, stating that “[t]he Administrator 

acknowledges that some aspects of climate change science and the 

projected impacts are more certain than others.”29 . The D.C. 

Circuit subsequently noted that “the existence of some 

uncertainty does not, without more, warrant invalidation of an 

endangerment finding.”30 

Some commenters also argued that the U.S. will adapt to 

climate change impacts and that therefore climate change impacts 

pose no threat. However, the D.C. Circuit, in CRR, held that 

considerations of adaption are irrelevant to the Endangerment 

determination. The Court stated, “These contentions are 

foreclosed by the language of the statute and the Supreme 

Court's decision in Massachusetts v. EPA” because “predicting 

society’s adaptive response to the dangers or harms caused by 

 

29 74 FR 66524. 30 CRR, 684 F.3d at 121. 

Comment [A31]: Please check citations to this 

case; although abbreviated here, it is fully spelled out 

in later footnotes 89 and 97. 
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climate change” does not inform the “scientific judgment” that 

the EPA is required to make regarding an Endangerment Finding.31 

Some commenters raised issues regarding the EPA Inspector 

General’s report, Procedural Review of EPA’s Greenhouse Gases 

Endangerment Finding Data Quality Processes.32 These commenters 

mischaracterized the report’s scope and conclusions and thus 

overstate the significance of the Inspector General’s procedural 

recommendations. Nothing in the Inspector General’s report 

questions the scientific validity of the Endangerment Finding, 

because that report did not evaluate the scientific basis of the 

Endangerment Finding. Rather, the Inspector General offers 

recommendations for clarifying and standardizing internal 

procedures for documenting data quality and peer review 

processes when referencing existing peer reviewed science in EPA 

actions.33 

 

31 Id. at 117. The EPA took a similar position in the 

Endangerment Finding, in which we responded to similar comments 

regarding society’s ability to adapt to climate change by 

stating: “Risk reduction through adaptation and GHG mitigation 

measures is of course a strong focal area of scientists and 

policy makers, including the EPA; however, the EPA considers 

adaptation and mitigation to be potential responses to 

endangerment, and as such has determined that they are outside 

the scope of the endangerment analysis.” 74 FR 66512. 

32 Report No. 11-P-0702 (September 26, 2011). 33 Unrelated to the Endangerment Finding and its validation by 

the Court, the EPA has made progress towards implementing the 

OIG recommendations. 

Comment [A32]: Spell out OIG in FN. 
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In addition, some commenters argued that the Endangerment 

Finding should be overturned because of the carbon dioxide 

fertilization effect, that is, the proposition that increased 

amounts of carbon dioxide can spur growth of vegetation. 

However, these commenters did not show how the science they 

provide on the subject differs from the carbon dioxide 

fertilization science already considered by the Administrator in 

the Endangerment Finding or how the existence of some benefits 

from the carbon dioxide fertilization effect could outweigh the 

numerous negative impacts of climate change. 

In sum, the EPA reviewed all of the comments purporting to 

refute the Endangerment Finding to determine whether they 

provide evidence that the Administrator’s judgment that climate 

change endangers public health and welfare was flawed, either 

because the Administrator misinterpreted the underlying 

assessments, because the science in new peer reviewed 

assessments differs from that in previous assessments, or 

because new individual studies provide compelling reasons for 

the EPA to change its interpretation of, or place less weight 

on, the major findings reflected in the assessment reports. In 

all cases, the commenters failed to demonstrate that the science 

that the Administrator relied on was inaccurate or that the 

science is of central relevance to the Administrator’s judgment 
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regarding endangerment.34 For these reasons, the commenters on 

the original proposal that criticized the Endangerment Finding 

have not provided a sufficient basis to cast doubt on the 

Finding. 

B. GHG emissions from fossil fuel-fired EGUs

Fossil fuel-fired electric utility generating units are by 

far the largest emitters of GHGs, primarily in the form of CO2, 

among stationary sources in the U.S., and among fossil fuelfired units, coal-fired units are by far the largest emitters. 

This section describes the amounts of those emissions and places 

those amounts in the context of the national inventory of GHGs. 

The EPA prepares the official U.S. Inventory of Greenhouse 

Gas Emissions and Sinks35 (the U.S. GHG Inventory) to comply with 

commitments under the United Nations Framework Convention on 

Climate Change (UNFCCC). This inventory, which includes recent 

trends, is organized by industrial sectors. It provides the 

information in Table 2 below, which presents total U.S. 

 

34 The EPA notes that commenters have previously submitted 

voluminous reviews of climate science as a part of their 

comments on rules. While the EPA will continue to consider the 

entirety of all submissions, the EPA’s responses will be 

primarily based on the comment itself. 

35 “Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990 – 

2011”, Report EPA 430-R-13-001, United States Environmental 

Protection Agency, April 15, 2013. 
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anthropogenic emissions and sinks of GHGs, including CO2

emissions, for the years 1990, 2005 and 2011.36

Table 2. U.S. GHG Emissions and Sinks by Sector (teragram carbon 

dioxide equivalent (Tg CO2 Eq.))37

SECTOR 1990 2005 2011 

Energy 

 

5,267.3 

 

6,251.6 

 

5,745.7 

Industrial Processes 

 

316.1 

 

330.8 

 

326.5 

Solvent and Other 

Product Use 

 

4.4 

 

4.4 

 

4.4 

Agriculture 

 

413.9 

 

446.2 

 

461.5 

Land Use, Land-Use 

Change and Forestry 

 

13.7 

 

25.4 

 

36.6 

Waste 

 

167.8 

 

136.9 

 

127.7 

Total Emissions 

 

6,183.3 

 

7,195.3 

 

6,702.3 

Land Use, Land-Use 

Change and Forestry 

(Sinks) 

 

(794.5) 

 

(997.8) (905.0) 

Net Emissions (Sources 

and Sinks) 

 

5,388.7 

 

6,197.4 

 

5,797.3 

Total fossil energy-related CO2 emissions (including both 

stationary and mobile sources) are the largest contributor to 

total U.S. GHG emissions, representing 78.7 percent of total 

 

36 Sinks are a physical unit or process that stores GHGs, such as 

forests or underground or deep sea reservoirs of carbon dioxide. 

37 From Table 2-3 of “Inventory of U.S. Greenhouse Gas Emissions 

and Sinks: 1990 – 2011”, April 15, 2013, EPA 430-R-13-001. 
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2011 GHG emissions. In 2011, fossil fuel combustion by the 

electric power sector –-entities that burn fossil fuel and whose 

primary business is the generation of electricity –- accounted 

for 39.6 percent of all energy-related CO2 emissions. Table 3 

below presents total CO2 emissions from fossil fuel-fired EGUs, 

for years 1990, 2005 and 2011.38

Table 3. U.S. GHG Emissions from Generation of Electricity from 

Combustion of Fossil Fuels (Tg CO2 Eq.) 

 

38 Note that for the purposes of reporting national GHG emissions 

under the UNFCCC, the U.S. GHG Inventory is calculated using 

internationally accepted methodological guidance from the 

Intergovernmental Panel on Climate Change (IPCC). In accordance 

with IPCC guidance, CO2 emissions from combustion of biogenic 

feedstocks are not reported in the energy sector, but are 

instead reported separately as a "Memo item" in the U.S. GHG 

Inventory. Consistent with the IPCC guidance, any carbon stock 

changes related to the use of biogenic feedstocks in the energy 

sector, and the CO2 emissions associated with those carbon stock 

changes, are accounted for under the forestry and/or 

agricultural sectors of the U.S. GHG Inventory. Attribution of 

CO2 emissions from the combustion of biogenic feedstocks by 

stationary sources in the energy sector to the forestry and/or 

agricultural sectors, in the context of U.S. GHG emissions 

reporting to the UNFCCC, should not be interpreted as an 

indication that such emissions are “carbon neutral.” 

GHG EMISSIONS 1990 2005 2011 

Total CO2 from fossil fuel 

combustion EGUs 

 

1,820.8 

 

2,402.1 

 

2,158.5 

 - from coal 

 

1,547.6 

 

1,983.8 

 

1,722.7 

 - from natural gas 

 

175.3 

 

318.8 

 

408.8 

 - from petroleum 

 

97.5 

 

99.2 

 

26.6 
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We are aware that nitrous oxide (N2O) and, to a lesser 

extent, methane (CH4) may be emitted from fossil fuel-fired EGUs, 

especially from coal-fired circulating fluidized bed (CFB) 

combustors and from units with selective catalytic reduction 

(SCR) and selective non-catalytic reduction (SNCR) systems 

installed for NOX control. The estimated emissions for N2O and 

CH4 from fossil fuel-fired EGUs are about 17.9 and 0.4 Tg of CO2

equivalent in 2011, respectively, which is about 0.8 percent of 

total CO2 equivalent emissions from fossil fuel-fired electric 

power generating units. However, we are not proposing separate 

N2O or CH4 emission limits or an equivalent CO2 emission limit in 

today’s notice because we lack more precise data on the quantity 

of these emissions and information on cost-effective controls. 

We request comment on this approach and we solicit information 

about the quantity of N2O and CH4 emissions from these affected 

sources and possible controls. 

C. The utility power sector and how its structure is changing

1. Utility power sector. 

The majority of power in the U.S. is generated from the 

combustion of coal, natural gas and other fossil fuels. 

Natural gas-fired EGUs typically use one of two technologies. 

Natural gas combined cycle (NGCC) units first generate power 
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from a combustion turbine (the combustion cycle). The unused 

heat from the combustion turbine is then routed to a Heat 

Recovery Steam Generator (HRSG) which generates steam which is 

used to generate power using a steam turbine (the steam cycle). 

The combining of these generation cycles increases the overall 

efficiency of the system. 

Simple cycle combustion turbines only use a single 

combustion turbine to produce electricity (i.e., there is no 

heat recovery). The power output from these simple cycle 

combustion turbines can be easily ramped up and down making them 

ideal for “peaking” operations. 

Coal-fired utility boilers are primarily either pulverized 

coal (PC) boilers or fluidized bed (FB) boilers. At a PC boiler, 

the coal is crushed (pulverized) into a powder in order to 

increase its surface area. The coal powder is then blown into a 

boiler and burned. In a coal-fired boiler using fluidized bed 

combustion, the coal is burned in a layer of heated particles 

suspended in flowing air. 

Power can also be generated using gasification technology. 

An integrated gasification combined cycle (IGCC) unit gasifies 

coal to form a syngas composed of carbon monoxide (CO) and 

hydrogen (H2), which can be combusted in a combined cycle system 

to generate power. 
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2. Changing structure of the power sector 

a. Technological developments and costs 

Since the April 2012 proposal, a few coal-fired units have 

reached the advanced stages of construction and development, 

which suggests that setting a separate standard for new fossil 

fuel-fired boilers and IGCC units is appropriate. Progress on 

Southern Company's Kemper County Energy Facility, which will 

deploy IGCC with partial CCS, has continued, and the project is 

now over 75% complete. Additionally, two other projects, Summit 

Power's Texas Clean Energy Project (TCEP) and the Hydrogen 

Energy California Project (HECA) – both of which will deploy 

IGCC with CCS – continue to move forward. The EIA modeling 

projects that coal-fired power generation will remain the single 

largest portion of the electricity sector beyond 2030. The EIA 

modeling also projects that few, if any, new coal-fired EGUs 

would be built in this decade and that those that are built 

would have CCS.39 Continued progress on these projects is 

consistent with the EIA modeling that suggests that a small 

number of coal-fired power plants may be constructed. The 

primary reasons for this rate of current and projected future 

 

39 Even in its sensitivity analysis, EIA does not project any 

additional coal beyond its reference case until 2023, in a case 

where power companies assume no GHGs emission limitations, and 

until 2025 in any sensitivity analysis in whichwhichthat assumes 

GHGs emission limitations. 
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development of new coal projects include highly competitive 

natural gas prices, lower electricity demand, and increases in 

the supply of renewable energy. 

Natural gas prices have decreased dramatically and 

generally stabilized in recent years, as new drilling techniques 

have brought additional supply to the marketplace and greatly 

increased the domestic resource base. As a result, natural gas 

prices are expected to be competitive for the foreseeable 

future, and EIA modeling and utility announcements confirm that 

utilities are likely to rely heavily on natural gas to meet new 

demand for electricity generation. On average, as discussed 

below, the cost of generation from a new natural-gas fired power 

plant (a natural gas combined cycle (NGCC) unit) is expected to 

be significantly lower than the cost of generation from a new 

coal-fired power plant.40 

Other drivers that may influence decisions to build new 

power plants are increases in renewable energy supplies, often 

due to state and federal energy policies. Many states have 

adopted renewable portfolio standards (RPS), which require a 

certain portion of electricity to come from renewable energy 

sources such as solar or wind. The federal government has also 

 

40 Levelized Cost of New Generation in the Annual Energy Outlook 

2011 http://205.254.135.24/oiaf/aeo/electricity_generation.html. 

Comment [A33]: EPA regulations, such as 

MATS, are not also a factor? 

Comment [A34]: The weblink provided in the 

footnote does not appear to work. Please provide a 

publicly accessible link to the report. 
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adopted incentives for electric generation from renewable energy 

sources and loan guarantees for new nuclear power plants. 

Due to these factors, the EIA projections from the last 

several years show that natural gas is likely to be the most 

widely-used fossil fuel for new construction of electric 

generating capacity through 2020, along with renewable energy, 

nuclear power, and a limited amount of coal with CCS. 

b. Energy sector modeling 

Various energy sector modeling efforts, including 

projections from the Energy Information Agency (EIA) and the 

EPA, forecast trends in new power plant construction and 

utilization of existing power plants that are consistent with 

the above-described technological developments and costs. The 

EIA forecasts the structure and developments in the power sector 

in its annual report, the Annual Energy Outlook (AEO). These 

reports are based on economic modeling and that reflects

existing policy and regulations, such as state RPS programs and 

federal tax credits for renewables.41 The current report, AEO 

2013, shows that although some coal-fired power plants are 

currently under construction and expected to begin operation in 

the next several years (referred to as “planned”), no new modelprojected (“unplanned”) coal-fired capacity will come online 

 

41 http://www.eia.gov/forecasts/aeo/chapter_legs_regs.cfm.

Comment [A35]: Please provide references to the 

projections. 
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after 2012. Instead, according to the AEO 2013, the vast 

majority of new generating capacity will be either natural gasfired or renewable, with a very small amount of new coal with 

CCS that is included in the AEO reference case in response to 

Federal and State incentives. The EIA projections from the last 

several years show that natural gas is likely to be the most 

widely-used fossil fuel for new construction of electric 

generating capacity through 2020.42 However, coal will remain an 

important part of the fuel mix for power generation, 

particularly for existing sources. Modeling from both the Energy 

Information Administration (EIA) and the EPA predict that coalfired generation will remain the largest single source of 

electricity in the U.S. through 2040. In the EIA’s AEO 2013,43

coal will supply 39 percent of all electricity in both 2020 and 

2025. 

The AEO 2013 projects the need for 25.9 GW of additional 

baseload or intermediate load generation capacity by 2020 (this 

includes projects that are under development (i.e., being 

constructed or in advance planning) and model-projected nuclear, 

coal, and NGCC projects). The vast majority of this new electric 

 

42 Annual Energy Outlook 2010, 2011, 2012, and 2013.

43 Energy Information Administration’sAdminstration’s Annual 

Energy Outlook for 2013, Final Release available at 

http://www.eia.gov/forecasts/aeo/index.cfm.
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capacity (22.5 GW) is already under development (under 

construction or in advanced planning); it includes about 6.1 GW 

of new coal-fired capacity, 5.5 GW of new nuclear capacity, and 

10.9 GW of new NGCC capacity. The EPA believes that most current 

fossil fuel-fired projects are already designed to meet limits 

consistent with today’s proposal (or they have already commenced 

construction and are thus not impacted by today’s notice). The 

AEO 2013 also projects an additional 3.4 GW of new baseload 

capacity additions, which are model-projected (unplanned). This 

consists of 3.1 GW of new NGCC capacity, and 0.3 GW of new coal 

equipped with CCS (incentivized with some government funding). 

Therefore, the AEO 2013 projections suggests that this proposal 

would only impact small amounts of new power generating capacity 

through 2020, all of which is expected to already meet the 

proposed emissions standards without incurring further control 

costs. In AEO 2013, this is also true through 2030, where new 

model-projected (unplanned) intermediate and baseload capacity 

is expected to be compliant with the proposed standard without 

incurring further control costs (48.2 GW of NGCC and 0.3 GW of 

coal with CCS, cumulative). 

The EPA modeling using the Integrated Planning Model (IPM), 

a detailed power sector model that the EPA uses to support power 

sector regulations, also shows limited future construction of 
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new coal-fired power plants under the base case.44 The EPA’s 

projections from IPM can be found in the RIA. 

c. Integrated Resource Plans 

The trends in the power sector described above are also 

apparent in many power companies’ publicly available long-term 

resource plans – termed Integrated Resource Plans (IRPs) - of 

many power companies. 

The EPA has reviewed publicly available IRPs from a range 

of companies (e.g., varying in size, location, current fuel 

mix), and these plans are generally consistent with both EIA and 

EPA modeling projections. Companies seem focused on demand-side 

management programs to lower future electricity demand and 

mostly reliant on a mix of new natural gas-fired generation and 

renewable energy to meet increased load demand and to replace 

retired generation capacity. 

Notwithstanding this clear trend towards natural gas-fired 

generation and renewables, many of the IRPs raise fuel 

diversity concerns and include options to diversify new 

generation capacity beyond natural gas and renewable 

energy. Several IRPs indicate that companies are 

considering new nuclear generation, including either 

traditional nuclear power plants or small modular reactors, 

and new coal-fired generation capacity with and without CCS 

technology. 

Based on these IRPs, the EPA acknowledges that a small 

 

44 http://www.epa.gov/airmarkets/progsregs/epaipm/BaseCasev410.html#documentation.

Comment [A36]: Please add a reference for this 

block quote. 

Has EPA considered referencing the Minnesota 

PUC’s recent decision on Great River Energy’s 

resource plan? 
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number of new fossil fuel-fired power plants may be built in the 

future. While this is contrary to the economic modeling 

predictions, the Agency understands that economic modeling may 

not fully reflect the range of factors that a particular company 

may consider when evaluating new generation options, such as 

fuel diversification. By the same token, as discussed below, it 

is possible that some of this potential new coal-fired 

construction may occur because developers are able to design 

projects that can provide competitively priced electricity for a 

specific geographic region. 

D. Statutory background

Section 111 of the Clean Air Act (the Standards of 

Performance for New Sources or NSPS program) establishes 

mechanisms for regulating emissions of air pollutants from 

stationary sources that are key in this rulemaking. As a 

preliminary step to regulation, the EPA must list categories of 

stationary sources that the Administrator, in his or her 

judgment, finds to “cause[], or contribute[] significantly to, 

air pollution which may reasonably be anticipated to endanger 

public health or welfare.”45 

 

45 CAA, §111(b)(1)(A). The EPA has made endangerment findings 

under this section for more than 60 stationary source categories 

and subcategories that are now subject to CAA section 111. 

Comment [A37]: EPA previously made 

endangerment findings for Subpart Da and KKKK 

sources when they were originally listed. citations 

to those should be added in this FN. 
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Once the EPA has listed a source category, the EPA proposes 

and then promulgates “standards of performance” for “new 

sources” in the category.46 “New source” include sources that 

“commence[]” either “construction” or “modification” after the 

date of the proposal.47 A modification is “any physical change 

... or change in the method of operation ... which increases the 

amount of any air pollutant emitted by such source or which 

results in the emission of any air pollutant not previously 

emitted,” unless it is a specific type of change, exempt from 

consideration as a modification, such as installation of 

pollution control projects.48 An existing facility is also 

considered a new source if it undertakes a “reconstruction,” 

which is the replacement of components to such an extent that 

the capital costs of the new equipment or components exceed 50 

percent of what is believed to be the cost of a completely new 

facility.49 In establishing standards of performance, the EPA has 

significant discretion to create subcategories based on source 

type, class or size.50 

 

46 CAA, §111 (b)(1)(B). 47 CAA, §111(a)(2). 48 CAA, §111(a)(4); 40 CFR 60.2, 60.14(e). 49 40 CFR 60.15. 50 CAA, §111(b)(2). 
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Clean Air Act section 111(a)(1) defines a “standard of 

performance” as 

a standard for emissions of air pollutants which 

reflects the degree of emission limitation achievable 

through the application of the best system of emission 

reduction which (taking into account the cost of 

achieving such reduction and any nonair quality health 

and environmental impact and energy requirements) the 

Administrator determines has been adequately 

demonstrated. 

We call this level of control the best system of emission 

reduction adequately demonstrated (BSER).51 The standard that the 

EPA develops, based on the BSER, is commonly a numerical 

emissions limit, expressed as a performance level (e.g., a ratebased standard). Generally, the EPA does not prescribe a 

particular technological system that must be used to comply with 

a standard of performance. Rather, sources generally can select 

any combination of measures that will achieve equivalent or 

greater control of emissions. 

Regarding other titles in the CAA, this rulemaking has 

implications for EGUs and other stationary sources in the CAA 

PSD program under Title I, part C, and the operating permits 

program under Title V. We discuss these implications in section 

 

51 We may occasionally refer to this level of control as the 

“best demonstrated system.” In the past, this level of control 

was frequently referred to as the “best demonstrated technology” 

(BDT). 

Comment [A38]: Has EPA considered adding 

examples of other NSPS that do prescribe a 

particular technological system? 
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X.

E. Regulatory and litigation background 

The EPA initially included fossil fuel-fired EGUs (which 

includes EGUs that burn fossil fuel including coal, gas, oil and 

petroleum coke and that use different technologies, including 

boilers and combustion turbines) in a category that it listed 

under section 111(b)(1)(A), and the EPA promulgated the first 

set of standards of performance for EGUs in 1971, codified in 

subpart D.52 As discussed in Section IV.D., the EPA has revised 

those regulations, and in some instances, revised the subparts, 

several times over the ensuing decades. None of these 

rulemakings or codifications, however, have constituted a new 

listing under CAA §111(b)(1)(A). 

In 1979, the EPA revised subpart D; as part of this 

revision, the EPA formed subpart Da and promulgated NSPS for 

electric utility steam generating units.53 These NSPS on June 11, 

1979 apply to units capable of firing more than 73 megawatts 

(MW) (250 MMBtu/h) heat input of fossil fuel that commenced 

construction, reconstruction, or modification after September 

 

52 “Standards of Performance for Fossil-Fuel-Fired Steam 

Generators for Which Construction Is Commenced After August 17, 

1971,” 36 Fed. Reg. 24875 (Dec. 23, 1971) codified at 40 CFR 

60.40-46; 36 Fed. Reg. 5931 (Mar. 31, 1971). 

53 “Standards of Performance for Electric Utility Steam 

Generating Units for Which Construction is Commenced After 

September 18, 1978 ,” 44 Fed. Reg. 33580 (June 11, 1979) 
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18, 1978. The NSPS for EGUs also apply to industrial-commercialinstitutional cogeneration units that sell more than 25 MW and 

more than one-third of their potential output capacity to any 

utility power distribution system. 

The EPA promulgated the most recent significant amendments 

to subpart Da in 2006, resulting in new criteria pollutant 

limitations for EGUs (the 2006 Final Rule).54,55 The 2006 Final 

Rule did not establish standards of performance for GHG 

emissions. Two groups of petitioners – 13 governmental entities 

and three environmental groups – filed petitions for judicial 

review of this rule by the D.C. Circuit.56 These petitioners 

 

54 ”Standards of Performance for Electric Utility Steam 

Generating Units, Industrial-Commercial-Institutional Steam 

Generating Units, and Small Industrial-Commercial-Institutional 

Steam Generating Units,” 71 Fed. Reg. 9866 (Feb. 27, 2006). 

55 The EPA has regulated emissions of conventional toxic air 

pollutants from power plants in numerous rulemakings, most 

recently in the Mercury and Air Toxics rule (“MATS”), 

“Reconsideration of Certain New Source Issues: National Emission 

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, IndustrialCommercial-Institutional, and Small Industrial-CommercialInstitutional Steam Generating Units,” 78 Fed. Reg. 24073 (April 

24, 2013). 

56State of New York, et al. v. EPA, No. 06–1322. The two groups 

of petitioners were (1) the States of New York, California, 

Connecticut, Delaware, Maine, New Mexico, Oregon, Rhode Island, 

Vermont and Washington; the Commonwealth of Massachusetts; the 

District of Columbia and the City of New York (collectively 

‘‘State Petitioners’’); and (2) Natural Resources Defense 

Council (NRDC), Sierra Club, and Environmental Defense Fund 

(EDF)(collectively ‘‘Environmental Petitioners’’). 
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contended, among other issues, that the rule was required to 

include standards of performance for GHG emissions from EGUs. 

The Court severed portions of the petitions for review of 

the 2006 Final Rule that related to GHG emissions. Following the 

U.S. Supreme Court’s 2007 decision in Massachusetts v. EPA, 

which gave authority to the EPA to regulate GHGs, the D.C. 

Circuit remanded the 2006 Final Rule to the EPA upon its own 

motion for further consideration of the issues related to GHG 

emissions in light of Massachusetts. The EPA did not act on that 

remand. Rather, these certain petitioners and the EPA negotiated 

a proposed settlement agreement that set deadlines for the EPA 

to propose and take final action on (1) a rule under CAA section 

111(b) that includes standards of performance for GHGs for new 

and modified EGUs that are subject to 40 CFR part 60, subpart 

Da; and (2) a rule under CAA section 111(d) that includes 

emission guidelines for GHGs from existing EGUs that would have 

been subject to 40 CFR part 60, subpart Da if they were new 

sources. Pursuant to CAA section 113(g), the EPA provided for a 

notice-and-comment opportunity on the proposed settlement 

agreement and, after reviewing the comments received, finalized 

the agreement. 

In June 2012, the D.C. Circuit in CRR upheld the EPA’s 

Endangerment Finding concerning GHGs and the EPA’s companion 

Comment [A39]: Insert year of settlement 

agreement? 
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finding that GHGs from motor vehicles contribute to the air 

pollution that endangers public health and welfare.57 The Court 

also upheld standards for motor vehicles that limited GHG 

emissions.58 In addition, the Court affirmed the EPA’s view that 

stationary source permitting requirements of the Clean Air Act 

are automatically applicable to a pollutant when that pollutant 

is regulated under any part of the Act. The Court also dismissed 

challenges to what we refer to as the Timing Decision59 and the 

Tailoring Rule,60 the EPA’s common sense approach to phasing in 

GHG permitting requirements to avoid an initial increase in the 

number of PSD and title V permit applications that would 

overwhelm the permitting authorities’ administrative capacities. 

In June 2012, industry entities filed petitions for review 

of the original proposal for this rulemaking action in the D.C. 

Circuit.61 In December 2012, the D.C. Circuit dismissed these 

petitions on grounds that the challenged proposed rule is not 

 

57 CRR, 684 F.3d 102; "Endangerment and Cause or Contribute 

Findings for Greenhouse Gases Under Section 202(a) of the Clean 

Air Act." 74 FR 66496 (December 15, 2009). 

58 "Light-Duty Vehicle Greenhouse Gas Emission Standards and 

Corporate Average Fuel Economy Standards; Final Rule." 75 FR 

25324 (May 7, 2010). 

59 "Interpretation of Regulations that Determine Pollutants 

Covered by Clean Air Act Permitting Programs." 75 FR 17004 

(April 2, 2010). 

60 Prevention of Significant Deterioration and Title V Greenhouse 

Gas Tailoring Rule; Final Rule. 75 FR 31514 (June 3, 2010). 

61 Las Brisas Energy Center, LLC v. EPA, No. 12-1248 and 

consolidated cases. 
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final agency action subject to judicial review. 

F. Coordination with other rulemakings

EGUs are the subject of several recent CAA rulemakings.62 In 

general, most EPA rulemakings affecting the power sector focus 

on existing sources. Therefore, few interactions are likely 

between other power sector rules and this rule, which focuses 

only on new sources. 

 We note that the EPA recently finalized revisions to the 

MATS rule as related to new sources.63 The revised MATS new 

source emission standards and the updated criteria pollutant new 

source performance standards, coupled with GHG performance 

standards in this proposed rule, provide a clear regulatory path 

for new fossil fuel-fired generation. 

The EPA recognizes that it is important that each of these 

efforts achieves its intended environmental objectives in a 

common-sense, cost-effective manner that is consistent with the 

 

62 We discuss other rulemakings solely for background purposes. 

The effort to coordinate rulemakings is not a defense to a 

violation of the CAA. Sources cannot defer compliance with 

existing requirements because of other upcoming regulations. 

63 “Reconsideration of Certain New Source Issues: National 

Emission 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 IndustrialCommercial-Institutional Steam Generating Units,” April 24, 2013 

(78 FR 24073). 

Comment [A40]: Don’t most also have 

requirements for new sources too? This seems to 

imply that they don’t. Maybe it should say “on 

existing sources as well as new sources”? 

Comment [A41]: It is odd to refer to this as a 

path. Suggest revising to say structure. 
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underlying statutory requirements and that minimize impacts on 

electricity rates and assure a reliable power system. Executive 

Order (EO) 13563 states that ‘‘[i]n developing regulatory 

actions and identifying appropriate approaches, each agency 

shall attempt to promote ... coordination, simplification, and 

harmonization. Each agency shall also seek to identify, as 

appropriate, means to achieve regulatory goals that are designed 

to promote innovation.’’ Recent guidance from the Office of 

Management and Budget’s Office of Information and Regulatory 

Affairs has emphasized the importance of, where appropriate and 

feasible, considering cumulative effects and seeking to 

harmonize rules in terms of both content and timing. We believe 

that these recent finalized and proposed rules will allow 

industry to comply with its obligations under these rules as 

efficiently as possible, by making coordinated investment 

decisions and, to the greatest extent possible, adopting 

integrated compliance strategies. 

G. Stakeholder input

The EPA extensively interacted with many different 

stakeholders regarding climate change, source contributions, and 

emission reduction opportunities. These stakeholders included 

industry entities, environmental organizations and many 

regional, state, and local air quality management agencies, as 
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well as the general public. As part of developing this proposed 

rule, the EPA held five listening sessions in February and March 

2011 to obtain additional information and input from key 

stakeholders and the public. Each of the five sessions had a 

particular target audience; these were the electric power 

industry, environmental and environmental justice organizations, 

states and Tribes, coalition groups and the petroleum refinery 

industry. Each session lasted two hours and featured a 

facilitated roundtable discussion among stakeholder 

representatives. The EPA asked key stakeholder groups to 

identify these roundtable participants in advance of the 

listening sessions. The EPA accepted comments from the public at 

the end of each session and via the electronic docket system.64 

On May 3, 2012, the EPA announced that it would hold two 

public hearings on the original proposed rule. The hearings were 

both held on May 24, 2012, in Washington, D.C. and Chicago, IL. 

Also on May 3, 2012, the EPA announced an extension of the 

public comment period for the original proposed rule, until June 

25, 2012. The EPA received approximately more than 2.5 million 

 

64 Comments related to the listening sessions submitted via the 

electronic docket system are available at www.regulations.gov 

(docket number EPA-HQ-OAR-2011-0090). 
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public comments on the original proposed rule.65 While the Agency 

is not preparing a response-to-comments document responding to 

the comments it received as part of that process, the EPA has 

taken into consideration those comments, as well as information 

received in the listening sessions, in developing this new 

proposal. 

III. Proposed Requirements for New Sources

This section describes the proposed requirements in this 

rulemaking for new sources. Our rationale for these proposed 

requirements is provided in Sections IV-X of this preamble. 

A. Affected sources

We generally refer to sources that would be subject to the 

standards of performance in this rulemaking variously as 

“affected” or “covered” sources, units, facilities, or simply as 

EGUs. These sources meet both the definition of “affected” and 

“covered” EGUs subject to an emission standard as provided by 

this rule, and the requirements for “new” sources as defined 

under the provisions of CAA section 111. 

1. Covered EGUs, generally 

Subpart Da currently defines an EGU as a boiler that is: 1) 

capable of combusting more than 250 MMBtu/h heat input of fossil 

 

65 Those comments are available at www.regulations.gov (docket 

number EPA-HQ-OAR-2011-0660). 
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fuel, 2) that is constructed for the purpose of supplying more 

than 1/3 of its potential net-electric output capacity to any 

utility power distribution system for sale, and 3) that is 

constructed for the purpose of supplying more than 25 MW netelectric output to any utility power distribution system for 

sale. We are proposing to define an EGU slightly differently 

than it is currently defined in subpart Da and in the April 2012 

proposal. First, we are proposing to use “supplies 1/3 of their 

potential electric output to the grid” instead of “constructed 

for the purpose of supplying more than 1/3 of their potential 

electric output to the grid” when determining applicability of 

the CO2 standard. This approach to applicability with the CO2

standard is similar to criteria pollutant emission standards 

included in both subparts Da and KKKK that vary depending on the 

fuels combusted. In this case, when EGUs do not supply more than 

1/3 of their potential electric output to the grid no CO2

emissions standard would be applicable. Second, we are proposing 

to use “more than 219,000 MWh,” as opposed to “25 MW,” netelectrical output to the grid. The proposed change of 25 MW net 

sales to 219,000 MWh net sales is consistent with the EPA Acid 

Rain Program (ARP) definition, and we have concluded that it is 

functionally equivalent to the 25 MW net sales language. The 25 

MW sales value has been interpreted to be the continuous sale of 
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25 MW of electricity on an annual basis, which is equivalent to 

219,000 MWh. We are also proposing the averaging period for 

electric sales from an annual basis to a three-year rolling 

average for stationary combustion turbines. Lengthening this 

period will ensure that the CO2 standards only apply to the 

intended facilities, which are intermediate and baseload EGUs. 

In addition, we are proposing to add a new applicability 

criterion that is not currently in subpart Da for the CO2

standard. Similar to the applicability requirements in the 

Mercury and Air Toxics Standard, we are proposing that EGUs,

where 10 percent or less of the heat input over a three-year 

period or which, is derived from a fossil fuel, are not subject 

to any of the proposed CO2 standards. 

For the purposes of this rule, we are proposing several 

additional changes to the way applicability is currently 

determined under subpart Da. First, we are proposing a different 

definition of potential electric output from the current 

definition in subpart Da. To assure that the applicability does 

not discourage the installation of the most efficient simple 

cycle turbines, we are proposing a definition of potential 

electric output that includes “or the design electric output 

efficiency on a net output basis” as an alternative to the 

default 33 percent default efficiency value. Next, we are 

Comment [A42]: Something is amiss with this 

sentence. Suggested edits for clarification. 
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proposing to add “of the thermal host facility or facilities” to 

the definition of net-electric output. This would make 

applicability consistent for both facility-owned CHP and 

qualifying third-party-owned CHP, since the owner of the CHP 

does not need to also own the thermal host facility. Finally, 

consistent with the intent expressed in the NSPS response to 

comments document of the MATS rule and the April 2012 proposal, 

we are proposing to amend the definition of a steam generating 

unit to include “plus any integrated equipment that provides 

electricity or useful thermal output to either the boiler or to 

power auxiliary equipment” and delete the existing language 

“plus any integrated combustion turbines and fuel cells.” We are 

also proposing to add the additional language to the definition 

of IGCC and stationary combustion turbine. 

2. CO2 emissions only 

This action proposes to regulate covered EGU emissions of 

CO2, and not other constituent gases of the air pollutant GHGs. 

We identify the pollutant we propose to regulate as GHGs, but, 

again, only CO2 emissions are subject to the proposed standard of 

performance. 

3. “New” sources 

CAA section 111(a)(2) defines a “new source” as “any 

stationary source, the construction or modification of which is 
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commenced after publication of regulations (or, if earlier, 

proposed regulations) prescribing a standard of performance 

under [CAA section 111] which will be applicable to such 

source.” In contrast, CAA section 111(a)(6) defines an “existing 

source” as “any stationary source other than a new source.” The 

definition of a “new source” applies according to its terms for 

purposes of this rulemaking. Note that we are not proposing 

standards for new steam generating units and stationary 

combustion turbines that sell less than 1/3 of their potential 

output to the grid, new non-natural gas-fired stationary 

combustion turbines, existing sources undertaking modifications 

or reconstructions, or certain projects under development as 

discussed below. As a result, if those types of sources commence 

construction or modification, they would not be subject to the 

standards of performance proposed today. 

4. Certain projects under development 

This proposal does not apply to the proposed Wolverine EGU 

project in Rogers City, Michigan. Based on current information, 

the Wolverine project appears to be the only fossil fuel-fired 

boiler or IGCC EGU project presently under development that may 

be capable of “commencing construction” for NSPS purposes in the 

very near future and, as currently designed, could not meet the 

1,100 lb CO2/MWh standard proposed for other new fossil fuelComment [A43]: What is included in this 

category and what is EPA’s rationale for not 

including such sources? Do they not fall under the 

Subpart Da or KKKK categories? 
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fired boiler and IGCC EGUs. The EPA has not formulated a view as 

to the project’s status in the development process or as to 

whether the proposed 1,100 lb CO2/MWh standard or some other CO2

standard of performance would be representative of BSER for this 

project and invites comment on this question.66 At the time of 

finalization of this proposal (but not sooner than one year 

following Federal Register publication of this proposal), if the 

Wolverine project remains under development and has not either 

“commenced construction” or been canceled, we anticipate 

proposing that the project either be made subject to the 1,100 

lb CO2/MWh standard or be assigned to a subcategory with an 

alternate CO2 standard. Further discussion is provided in the 

 

66 The EPA’s lack of view regarding the appropriate CO2 standard 

is closely related to the existence of conflicting information 

on where the project stands in the development process. The 

developer has claimed that the project was delayed by issues 

related to the standards of performance for hazardous air 

pollutants promulgated in December 2011, 77 FR 9304 (Feb. 16, 

2012) (Mercury and Air Toxics Standards, or MATS). Specifically, 

the developer cited a perceived inability to obtain guarantees 

from pollution control equipment vendors that the plant would 

achieve the MATS standards. See Jim Dulzo, As Coal Plant 

Teeters, Groups Mount Legal Attack, Michigan Land Use Institute 

blog, Feb. 13, 2012, http://www.mlui.org/energy/news-views/newsviews-articles/as-coal-plant-teeters-groups-mount-legalattack.html. While some of the MATS new-unit standards were 

revised upon reconsideration in March 2013, 78 FR 24073 (Apr. 

24, 2013), the developer’s claims raise the possibility that the 

EPA’s own actions may have delayed the project and contributed 

to the present uncertainty as to the project’s development 

status. 
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technical support document in the docket entitled “Fossil FuelFired Boiler and IGCC EGU Projects under Development: Status and 

Approach.” 

There are two other fossil fuel-fired boiler or IGCC EGU 

projects without CCS – the Washington County project in Georgia 

and the Holcomb project in Kansas – that appear to remain under 

development but whose developers have recently represented that 

the projects have “commenced construction” for NSPS purposes. 

Based solely on the developers’ representations, the projects 

would be existing sources, and thus not subject to this 

proposal. However, neither developer has sought an EPA 

determination of NSPS applicability; and if upon review it was 

determined that the projects have not “commenced constructions,” 

the projects could be situated similarly to the Wolverine 

project. Accordingly, we propose that if either developer seeks 

an EPA determination of applicability within 120 days following 

Federal Register publication of this proposal and the EPA finds 

that the project has not “commenced construction,” as of the 

date of the Federal Register publication of this proposal, then 

that project automatically – without, for example, any 

supplemental proposal or re-proposal – would be addressed in the 
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same manner as the Wolverine project.67 Further discussion is 

provided in the technical support document in the docket 

referenced above.68 

We invite comment on all aspects of this approach for 

addressing the Wolverine project (and the Washington County and 

Holcomb projects, if applicable).69

 

67 In this event, there will not be any proposed standard “which 

will be applicable to such source” within the meaning of CAA 

section 111(a)(2), and to the extent that this proposal did, 

until the time of the applicability determination, apply to that 

project, this proposal will be considered automatically to be 

withdrawn as it applies to that project as of the time of the 

applicability determination. The purpose of this automatic 

withdrawal is to ensure that the project is placed on the same 

footing as the Wolverine project as soon as possible. It is 

worth noting that, if the developers do not seek applicability 

determinations within the 120 day timeframe, nothing in this 

rulemaking binds the EPA to the position that the projects have 

“commenced construction” for NSPS purposes. 

68 In the April 2012 GHG NSPS proposal, the Wolverine, Washington 

County, and Holcomb projects were among a group of 15 projects 

distinguished from other EGU projects as “potential transitional 

sources.” This proposal does not continue that distinction. 

Except as described above for the Wolverine project, and 

possibly the Washington County and Holcomb projects, any former 

“potential transitional source” that commences construction 

after publication of this proposal (and meets any other 

applicability criteria) will be subject to the final CO2

standards established in this rulemaking. Any former “potential 

transitional source” that commenced construction prior to 

publication of this proposal is an existing source not subject 

to the CO2 standards established in this rulemaking, but instead 

subject to the CO2 standards that will bebeare required to be 

established for existing sources pursuant to CAA section 111(d).

69 The EPA intends that its treatment of the Wolverine project 

(and the Washington County and Holcomb projects, if applicable) 

be severable from its treatment of differently situated sources 

and considers that severability is logical because of the 
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B. Emission standards

In this rulemaking, the EPA is proposing standards of 

performance (NSPS) for CO2 emissions from several subcategories 

of affected sources, which are new fossil fired EGUs described 

above in Section III.A. 

1. Standards of performance for affected sources 

The proposed standard of performance for each subcategory 

is in the form of a gross output-based CO2 emission limit 

expressed in units of emissions mass per unit of useful 

recovered energy, specifically, in pounds per megawatt-hour 

(lb/MWh). This emission limit would apply to affected sources 

upon the effective date of the final action. 

The subcategories, for which the EPA is proposing separate 

standards of performance, are (1) natural gas-fired stationary 

combustion turbines with a heat input rating that is greater 

than 850 MMBtu/h;70 (2) natural gas-fired stationary combustion 

turbines with a heat input rating that is less than or equal to 

 

record-based differences between these sources and differently 

situated sources and because there is no interdependency in the 

EPA’s treatment of the different types of sources. This 

statement concerning severability should not be construed to 

have implications for whether other components in this 

rulemaking are severable.

70 This subcategorization of stationary combustion turbines is 

consistent with the subcategories used in the combustion turbine 

(subpart KKKK) criteria pollutant NSPS. The size limit of 850 

MMBtu/h corresponds to approximately 100 MWe. 
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850 MMBtu/h, which are also natural gas fired; and (3) all 

fossil fuel-fired boilers and IGCC units, which generally are 

solid-fuel fired. 

We are proposing that all affected new fossil fuel-fired 

EGUs are required to meet an output-based emission rate of a 

specific mass of CO2 per MWh of useful output. Specifically, new 

combustion turbines with a heat input rating greater than 850 

MMBtu/h would be required to meet a standard of 1,000 lb CO2/MWh. 

New combustion turbines with a heat input rating less than or 

equal to 850 MMBtu/h would be required to meet a standard of 

1,100 lb CO2/MWh. As discussed below, these proposed standards 

are based on the demonstrated performance of recently 

constructed natural gas combined cycle (NGCC) units, which are 

currently in wide use throughout the country, and are currently 

the predominant fossil fuel-fired technology for new electric 

generating units in the near future. 

New fossil fuel-fired boilers and IGCC units would be 

required, based on the performance of currently available CCS 

technology, to meet a standard of 1,100 lb CO2/MWh on a 12-

operating-month rolling average, or alternatively a lower 

standard, which we propose as between 950 lb CO2/MWh and 1,050 lb 

CO2/MWh, on a 60-operating-month rolling average as an 

equivalently stringent standard. The EPA has previously offered 
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sources optional, longer-term emission standards that are 

discounted from the primary emissions standard in exchange 

forcombination with the a longer averaging period. We are 

requesting comment on the appropriate numerical standard such 

that the 60-operating-month standard would be as stringent as or 

more stringent than the 12-operating-month standard. We also 

request comment on an appropriate 12-operating-month standard 

that owners/operators electing to comply with the 60-operatingmonth standard would have to comply with. This standard would be 

numerically between the alternate 12-operating-month standard 

and an emissions rate of a coal-fired EGU without CCS (e.g., 

1,800 lb CO2/MWh). This shorter term standard would be more 

easily enforced and assure adequate emission reductions. 

While the EPA is proposing specific standards of performance 

for each subcategory, we are also taking comment on a range of 

potential emission limitations. We solicit comment on a range of 

950 – 1,100 lb CO2/MWh for new stationary combustion turbines 

with a heat input rating greater than 850 MMBtu/h. We also 

solicit comment on an emission limitation range of 1,000 – 1,150 

lb CO2/MWh for new stationary combustion turbines with a heat 

input rating less than or equal to 850 MMBtu/h. In addition, we 

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

Comment [A44]: “in exchange for” sounds like 

it’s a negotiation. 

Comment [A45]: This is unclear. Can EPA be 

more specific about what goal the shorter term 

standard would be trying to achieve? To ensure that 

sources are on track to meet the longer term target? 
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CO2/MWh. 

As discussed below, the proposed method to calculate 

compliance is to sum the emissions for all operating hours and 

to divide that value by the sum of the useful energy output over 

a rolling 12-operating-month period. In the alternative, we 

solicit comment on requiring calculation of compliance on an 

annual (calendar year) period. 

To recognize the environmental benefit of reduced electric 

transmission and distribution losses of CHP, we are proposing 

that CHP facilities where at least 20.0 percent of the total 

gross useful energy output consists of electric or direct 

mechanical output and 20.0 percent of the total gross useful 

energy output consists of useful thermal output on a rolling 

three calendar year basis receive similar credit as currently in 

subpart Da and the proposed amendments to subpart KKKK (77 FR 

52554). Specifically, the measured electric output would be 

divided by 0.95 to account for a five percent energy loss in the 

transmission of electricity. The minimal electric and thermal 

output requirements are to avoid owners/operators from selling 

trivial amounts of thermal output and claiming a line loss 

benefit when in reality they are similar to a central power 

station. 

Comment [A46]: Should this say avoided energy 

loss? 
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In the April 2012 proposal, we requested comment on 

requiring the use of net output based standards. Part of the 

rationale behind that approach is that the use of a gross 

output-based standard as currently defined could potentially 

drive the installation of electrically driven feed pumps instead 

of steam driven feed pumps at a steam generating unit, even 

though from an overall net efficiency basis it may be more 

efficient to use steam-driven feed pumps. Subpart Da currently 

defines gross electric output from steam generating units as the 

“gross electrical or mechanical output from the affected 

facility minus any electricity used to power the feedwater pumps 

and any associated gas compressors (air separation unit main 

compressor, oxygen compressor, and nitrogen compressor) plus 75 

percent of the useful thermal output measured relative to ISO 

conditions.” We have concluded that the feedwater pump 

efficiency impacts are primarily relevant to steam generating 

units, as combustion turbine based generators (and IGCC 

facilities) typically do not use steam driven feedwater pumps. 

Therefore, measuring the electric load of these pumps is 

unnecessarily burdensome for NGCC and IGCC facilities. In 

addition, we have concluded that measuring the electricity used 

by gas compressors is also unnecessarily burdensome as they are 

an inherent part of the currently available IGCC process. 
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Therefore, we are proposing the gross electric output for 

steam generating units be the electricity measured at the 

generator terminals minus electric power used to run the 

feedwater pumps, and the gross electric output for IGCC and 

subpart KKKK affected facilities would be the electricity 

measured at the generator terminals. We are proposing that with 

respect to CO2 emissions, 75 percent credit is the appropriate 

discount factor for useful thermal output. However, we are 

requesting comment on a range of two-thirds to three-fourths 

credit for useful thermal output in the final rule. 

2. 60-operating-month rolling average compliance option 

We also propose a 60-operating-month rolling averaging 

compliance option that would be available for affected boilers 

and IGCC facilities. The EPA suggests that this 60-operatingmonth rolling average compliance option will offer operational 

flexibility and will tend to dampen short-term emission 

excursions, which may be warranted especially at the initial 

startup of the facility and the CCS system. 

We have concluded that this alternative compliance option 

is not necessary for new stationary combustion turbine EGUs, as 

they should be able to meet the proposed performance standard 

with no need for add-on technology. We seek comment on all other 

aspects of this 60-operating-month rolling averaging compliance 
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option. 

C. Startup, shutdown, and malfunction requirements

1. Startups and shutdowns 

Consistent with Sierra Club v. EPA, the EPA is proposing 

standards in this rule that apply at all times, including during 

startups and shutdowns. In proposing the standards in this rule, 

the EPA has taken into account startup and shutdown periods and, 

for the reasons explained below has not proposed alternate 

standards for those periods. In the compliance calculation, 

periods of startup and shutdown are included as periods of 

partial load. To establish the proposed NSPS’s output-based CO2

standard, we accounted for periods of startup and shutdown by 

incorporating them as periods of partial load operation. As 

noted above, the proposed method to calculate compliance is to 

sum the emissions for all operating hours and to divide that 

value by the sum of the electrical energy output and useful 

thermal energy output, where applicable for CHP EGUs, over a 

rolling 12-operating-month period. This averaging approach gives 

more weight to high-load hours and more accurately reflects 

overall environmental performance. Periods of startup and 

shutdown will be short, relative to total operating time. Since 

we are primarily concerned with overall environmental 

performance over extended periods of time, incorporating 

Comment [A47]: This case is referenced below, 

but this appears to be the first reference. Please add 

full cite. 
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relatively short periods of partial load has a negligible effect 

on measuring performance of the source with respect to long-term 

efficiency. Thus we allowed that low-load hours do not factor as 

heavily into the calculated average performance of the source. 

We solicit comment on any alternative to our proposal that 

the periods of startup and shutdown be included as periods of 

partial load in the 12- and 60-operating-month rolling averaging 

compliance option. 

2. Malfunctions 

Periods of startup, normal operations, and shutdown are all 

predictable and routine aspects of a source’s operations. 

However, by contrast, malfunction is defined as a “sudden, 

infrequent, and not reasonably preventable failure of air 

pollution control and monitoring equipment, process equipment or 

a process to operate in a normal or usual manner. Failures that 

are caused in part by poor maintenance or careless operations 

are not malfunctions.’’(40 CFR 60.2). The EPA has determined 

that CAA section 111 does not require that emissions that occur 

during periods of malfunction be factored into development of 

CAA section 111 standards. Nothing in CAA section 111 or in case 

law requires that the EPA anticipate and account for the 

innumerable types of potential malfunction events in setting 

emission standards. CAA section 111 provides that the EPA set 
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standards of performance which reflect the degree of emission 

limitation achievable through ‘‘the application of the best 

system of emission reduction’’ that the EPA determines is 

adequately demonstrated. Applying the concept of ‘‘the 

application of the best system of emission reduction’’ to 

periods during which a source is malfunctioning presents 

difficulties. The ‘‘application of the best system of emission 

reduction’’ is more appropriately understood to include 

operating units in such a way as to avoid malfunctions. 

Further, accounting for malfunctions would be difficult, if 

not impossible, given the myriad different types of malfunctions 

that can occur across all sources in the category and given the 

difficulties associated with predicting or accounting for the 

frequency, degree, and duration of various malfunctions that 

might occur. As such, the performance of units that are 

malfunctioning is not “reasonably” foreseeable. See, e.g., 

Sierra Club v EPA, 167 F.3d 658, 662 (D.C. Cir. 1999) (The EPA 

typically has wide latitude in determining the extent of datagathering necessary to solve a problem. We generally defer to an 

agency's decision to proceed on the basis of imperfect 

scientific information, rather than to "invest the resources to 

conduct the perfect study."). See also, Weyerhaeuser v. Costle,

590 F.2d 1011, 1058 (DC Cir. 1978) (“In the nature of things, no 
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general limit, individual permit, or even any upset provision 

can anticipate all upset situations. After a certain point, the 

transgression of regulatory limits caused by ‘uncontrollable 

acts of third parties,’ such as strikes, sabotage, operator 

intoxication or insanity, and a variety of other eventualities, 

must be a matter for the administrative exercise of case-by-case 

enforcement discretion, not for specification in advance by 

regulation”). In addition, the goal of a source that uses the 

best system of emission reduction is to operate in such a way as 

to avoid malfunctions of the source and accounting for 

malfunctions could lead to standards that are significantly less 

stringent than levels that are achieved by a well-performing 

non-malfunctioning source. The EPA’s approach to malfunctions is 

consistent with section 111 and is a reasonable interpretation 

of the statute. 

In the event that a source fails to comply with the 

applicable CAA section 111 standards as a result of a 

malfunction event, the EPA would determine an appropriate 

response based on, among other things, the good faith efforts of 

the source to minimize emissions during malfunction periods, 

including preventative and corrective actions, as well as root 

cause analyses to ascertain and rectify excess emissions. The 

EPA would also consider whether the source's failure to comply 
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with the CAA section 111 standard was, in fact, “sudden, 

infrequent, not reasonably preventable” and was not instead 

“caused in part by poor maintenance or careless operation.” 40 

CFR section 60.2 (definition of malfunction). 

Finally, the EPA recognizes that even equipment that is 

properly designed and maintained can sometimes fail and that 

such failure can sometimes cause a violation of the relevant 

emission standard. (See, e.g., State Implementation Plans: 

Response to Petition for Rulemaking; Finding of Excess Emissions 

During Periods of Startup, Shutdown, and Malfunction; Proposed 

Rule, 78 FR 12460 (Feb. 22, 2013): (State Implementation Plans: 

Policy Regarding Excessive Emissions During Malfunctions, 

Startup, and Shutdown (Sept. 20, 1999); Policy on Excess 

Emissions During Startup, Shutdown, Maintenance, and 

Malfunctions (Feb. 15, 1983)). The EPA is therefore proposing to 

add an affirmative defense to civil penalties for violations of 

emission standards that are caused by malfunctions. See 40 CFR 

60.10042 (defining “affirmative defense” to mean, in the context 

of an enforcement proceeding, a response or defense put forward 

by a defendant, regarding which the defendant has the burden of 

proof, and the merits of which are independently and objectively 

evaluated in a judicial or administrative proceeding). We also 

are proposing other regulatory provisions to specify the 
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elements that are necessary to establish this affirmative 

defense; the source must prove by a preponderance of the 

evidence that it has met all of the elements set forth in 

60.5530. (See 40 CFR 22.24). The criteria are designed in part 

to ensure that the affirmative defense is available only where 

the event that causes a violation of the emission standard meets 

the narrow definition of malfunction in 40 CFR 60.2 (sudden, 

infrequent, not reasonably preventable and not caused by poor 

maintenance and or careless operation). For example, to 

successfully assert the affirmative defense, the source must 

prove by a preponderance of the evidence that the violation 

“[w]as caused by a sudden, infrequent, and unavoidable failure 

of air pollution control, process equipment, or a process to 

operate in a normal or usual manner....” The criteria also are 

designed to ensure that steps are taken to correct the 

malfunction, to minimize emissions in accordance with section 

60.10001 and to prevent future malfunctions. For example, the 

source must prove by a preponderance of the evidence that 

“[r]epairs were made as expeditiously as possible when a 

violation occurred...” and that “[a]ll possible steps were taken 

to minimize the impact of the violation on ambient air quality, 

the environment and human health....” In any judicial or 

administrative proceeding, the Administrator may challenge the 
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assertion of the affirmative defense and, if the respondent has 

not met its burden of proving all of the requirements in the 

affirmative defense, appropriate penalties may be assessed in 

accordance with section 113 of the CAA (see also 40 CFR part 

22.27). 

The EPA included an affirmative defense in the proposed 

rule in an attempt to balance a tension, inherent in many types 

of air regulation, to ensure adequate compliance while 

simultaneously recognizing that despite the most diligent of 

efforts, emission standards may be violated under circumstances 

beyond the control of the source. The EPA must establish 

emission standards that “limit the quantity, rate, or 

concentration of emissions of air pollutants on a continuous 

basis.” 42 U.S.C. §7602(k)(defining “emission limitation” and 

“emission standard”). See generally Sierra Club v. EPA, 551 F.3d 

1019, 1021 (D.C. Cir. 2008) Thus, the EPA is required to ensure 

that section 111 emissions standards are continuous. The 

affirmative defense for malfunction events meets this 

requirement by ensuring that even where there is a malfunction, 

the emission standard is still enforceable through injunctive 

relief. The United States Court of Appeals for the Fifth Circuit 

recently upheld the EPA’s view that an affirmative defense 

provision is consistent with section 113(e) of the Clean Air 
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Act. Luminant Generation Co. LLC v. United States EPA, 2013 U.S. 

App. LEXIS 6397 (5th Cir. Mar. 25, 2013) 699 F3d. 427(5th Cir. 

Oct. 12, 2012) (upholding the EPA’s approval of affirmative 

defense provisions in a CAA State Implementation Plan). While 

“continuous” standards, on the one hand, are required, there is 

also case law indicating that in many situations it is 

appropriate for the EPA to account for the practical realities 

of technology. For example, in Essex Chemical v. Ruckelshaus, 

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

acknowledged that in setting standards under CAA section 111 

“variant provisions” such as provisions allowing for upsets 

during startup, shutdown and equipment malfunction “appear 

necessary to preserve the reasonableness of the standards as a 

whole and that the record does not support the ‘never to be 

exceeded’ standard currently in force.” See also, Portland 

Cement Association v. Ruckelshaus, 486 F.2d 375 (D.C. Cir. 

1973). Though intervening case law such as Sierra Club v. EPA 

and the CAA 1977 amendments call into question the relevance of 

these cases today, they support the EPA’s view that a system 

that incorporates some level of flexibility is reasonable. The 

affirmative defense simply provides for a defense to civil 

penalties for violations that are proven to be beyond the 

control of the source. By incorporating an affirmative defense, 

Comment [A48]: The relevance is questioned 

with respect to other issues? Add clarifying 

statement. 
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the EPA has formalized its approach to malfunctions. In a Clean 

Water Act setting, the Ninth Circuit required this type of 

formalized approach when regulating “upsets beyond the control 

of the permit holder.” Marathon Oil Co. v. EPA, 564 F.2d 1253, 

1272-73 (9th Cir. 1977). See also, Mont. Sulphur & Chem. Co. v. 

United States EPA, 666 F.3d. 1174 (9th Cir. 2012)(rejecting 

industry argument that reliance on the affirmative defense was 

not adequate). But see, Weyerhaeuser Co. v. Costle, 590 F.2d 

1011, 1057-58 (D.C. Cir. 1978) (holding that an informal 

approach is adequate). The affirmative defense provisions give 

the EPA the flexibility to both ensure that its emission 

standards are “continuous” as required by 42 U.S.C. §7602(k), 

and account for unplanned upsets and thus support the 

reasonableness of the standard as a whole. 

We propose that these same requirements, an affirmative 

defense to civil penalties for violations of emission limits 

that are caused by malfunctions, would apply to both the 12-

operating-month standard and the 60-operating-month rolling 

average compliance option; however, we will take comment on 

whether it is appropriate to have an affirmative defense for the 

60-operating-month rolling average portion of that compliance 

option, given that we would expect malfunctions to only impact 

shorter averaging periods, and the longer the compliance period, 
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the less likely malfunction events are to impact a source’s 

ability to meet the standard. 

D. Continuous monitoring requirements

Today’s proposed rule would require owners or operators of 

EGUs that combust solid fuel to install, certify, maintain, and 

operate continuous emission monitoring systems (CEMS) to measure 

CO2 concentration, stack gas flow rate, and (if needed) stack gas 

moisture content in accordance with 40 CFR Part 75, in order to 

determine hourly CO2 mass emissions rates (tons/hr). 

 The proposed rule would allow owners or operators of EGUs 

that burn exclusively gaseous or liquid fuels to install fuel 

flow meters as an alternative to CEMS and to calculate the 

hourly CO2 mass emissions rates using Equation G-4 in Appendix G 

of Part 75. To implement this option, hourly measurements of 

fuel flow rate and periodic determinations of the gross 

calorific value (GCV) of the fuel are also required, in 

accordance with Appendix D of Part 75. 

 In addition to monitoring the CO2 mass emission rate, the 

proposed rule would require EGU owners or operators to monitor 

the hourly unit operating time and “gross output”, expressed in 

megawatt hours (MWh). The gross output includes electrical 

output plus any mechanical output, plus 75 percent of any useful 

thermal output. 
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 The proposed rule would require EGU owners or operators to 

prepare and submit a monitoring plan that includes both 

electronic and hard copy components, in accordance with 

§§75.53(g) and (h). The electronic portion of the monitoring 

plan would be submitted to the EPA’s Clean Air Markets Division 

(CAMD) using the Emissions Collection and Monitoring Plan System 

(ECMPS) Client Tool. The hard copy portion of the plan would be 

sent to the applicable State and EPA Regional office. Further, 

all monitoring systems used to determine the CO2 mass emission 

rates would have to be certified according to §75.20 and section 

6 of Part 75, Appendix A within the 180-day window of time 

allotted under §75.4(b), and would be required to meet the 

applicable on-going quality assurance procedures in Appendices B 

and D of Part 75. 

The proposed rule would require all valid data recorded by 

the monitoring systems (including data recorded during startup, 

shutdown, and malfunction) to be used in assessing compliance. 

Failure to collect required data is a violation of the 

monitoring requirements, except for periods of monitoring system 

malfunctions, repairs associated with monitoring system 

malfunctions, and required monitoring system quality assurance 

or quality control activities that temporarily interrupt the 

measurement of stack emissions (e.g., calibration error tests, 
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linearity checks, and required zero and span adjustments). An 

affirmative defense to civil penalties for malfunctions is 

available to a source if it can demonstrate that certain 

criteria and requirements are satisfied. 

The proposed rule would require only those operating hours 

in which valid data are collected for all of the parameters in 

the CO2 mass emission rate equation to be used for compliance 

purposes. Additionally for EGUs using CO2 CEMS, only unadjusted 

stack gas flow rate values would be used in the emissions 

calculations. In this proposal, Part 75 bias adjustment factors 

(BAFs) would not be applied to the flow rate data. These 

restrictions on the use of Part 75 data for Part 60 compliance 

are consistent with previous NSPS regulations and revisions. 

The following variations from and additions to the basic Part 75 

monitoring would be required: 

 If you determine compliance using CEMS, you would be 

required to use a laser device to measure the stack 

diameter at the flow monitor and the reference method 

sampling locations prior to the initial setup 

(characterization) of the flow monitor. For circular 

stacks, you would make three determinations of the 

diameter and average the results. For rectangular stacks 

or ducts, you would make three measurements of each 
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dimension (i.e., depth and width) and average the results. 

If the flow rate monitor or reference method sampling site 

is relocated, you would repeat these measurements at the 

new location. 

 If you elect to use Method 2 in Appendix A-1 of Part 60 to 

perform the required relative accuracy test audits (RATAs) 

of the Part 75 flow rate monitoring system, you would have 

to use a calibrated Type-S pitot tube or pitot tube 

assembly. Use of the default Type-S pitot tube coefficient 

would not be permitted. 

 If your EGU combusts natural gas and/or fuel oil and you 

elect to measure the CO2 mass emissions rate using Equation 

G-4 in Appendix G of Part 75, you would be allowed to 

determine site-specific carbon-based F-factors using 

Equation F-7b in section 3.3.6 of Appendix F of Part 75, 

and you could use these Fc values in the emissions 

calculations instead of using the default Fc values in the 

Equation G-4 nomenclature. 

Today’s proposed rule includes the following special 

compliance provisions for units with common stack or multiple 

stack configurations; these provisions are consistent with 

§60.13(g): 
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 If two or more of your EGUs share a common exhaust stack, 

are subject to the same emission limit, and you are 

required to (or elect to) determine compliance using CEMS, 

you would be allowed to monitor the hourly CO2 mass 

emission rate at the common stack instead of monitoring 

each EGU separately. If this option is chosen, the hourly 

gross electrical load (or steam load) would be the sum of 

the hourly loads for the individual EGUs and the operating 

time would be expressed as “stack operating hours” (as 

defined in 40 CFR 72.2). Then, if compliance with the 

applicable emission limit is attained at the common stack, 

each EGU sharing the stack would be considered to be in 

compliance. 

 If you are required to (or elect to) determine compliance 

using CEMS and the effluent from your EGU discharges to 

the atmosphere through multiple stacks (or, if the 

effluent is fed to a stack through multiple ducts and you 

choose to monitor in the ducts), you would be required to 

monitor the hourly CO2 mass emission rate and the “stack 

operating time” at each stack or duct separately. In this 

case, compliance with the applicable emission limit would 

be determined by summing the CO2 mass emissions measured at 
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the individual stacks or ducts and dividing by the total 

gross output for the unit. 

The proposed rule would require 95 percent of the operating 

hours in each compliance period (including the compliance 

periods for the intermediate emission limits to be “valid 

hours,” i.e., operating hours in which quality-assured data are 

obtained for all of the parameters used to calculate CO2 mass 

emissions. EGU owners or operators would have the option to use 

backup monitoring systems, as provided in §§75.10(e) and 

75.20(d), to help meet this proposed data capture requirement. 

E. Emissions performance testing requirements

In accordance with §75.64(a), the proposed rule would 

require an EGU owner or operator to begin reporting emissions 

data when monitoring system certification is completed or when 

the 180-day window in §75.4(b) allotted for initial 

certification of the monitoring systems expires (whichever date 

is earlier). For EGUs subject to the 450 kg/MWh (1,000 lb/MWh) 

standard or the 500 kg/MWh (1,100 lb/MWh) emission standard, the 

initial performance test would consist of the first 12-

operating-months of data, starting with the month in which 

emissions are first required to be reported. The initial 12-

operating-month compliance period would begin with the first 

month of the first calendar year of EGU operation in which the 
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facility exceeds the capacity factor applicability threshold. 

The traditional 3-run performance tests (i.e., stack tests) 

described in §60.8 would not be required for this rule. 

Following the initial compliance determination, the emission 

standard would be met on a 12-operating-month rolling average 

basis. For EGUs that combust coal and/or petroleum coke and 

whose owners or operators elect to comply with the alternative 

60-operating-month rolling average emissions standard, the first 

month in the compliance period would be the month in which 

emissions reporting is required to begin under §75.64(a). 

F. Continuous compliance requirements

Today’s proposed rule specifies that compliance with the 

450 kg/MWh (1,000 lb/MWh) and 500 kg/MWh (1,100 lb/MWh) CO2 mass 

emissions rate limits would be determined on a 12-operatingmonth rolling average basis, updated after each new operating 

month. For each 12-operating-month compliance period, qualityassured data from the certified Part 75 monitoring systems would 

be used together with the gross output over that period of time 

to calculate the average CO2 mass emissions rate. 

The proposed rule specifies that the first operating month 

included in either the initial 12- or 60-operating-month 

compliance period would be the month in which reporting of 

emissions data is required to begin under §75.64(a), i.e., 

Comment [A49]: In most instances, the rule lists 

the lb/Mwh - suggest putting kg/MWh in 

parenthesis here for consistency. 
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either the month in which monitoring system certification is 

completed or the month in which the 180-day window allotted to 

finish certification testing expires (whichever month is 

earlier). 

We are proposing that initial compliance with the 

applicable emissions limit in kg/MWh be calculated by dividing 

the sum of the hourly CO2 mass emissions values by the total 

gross output for the 12- or 60-operating-month period. Affected 

EGUs would continue to be subject to the standards and 

maintenance requirements in the section 111 regulatory general 

provisions contained in 40 CFR part 60, subpart A. 

G. Notification, recordkeeping, and reporting requirements

Today’s proposed rule would require an EGU owner or 

operator to comply with the applicable notification requirements 

in §75.61, §§60.7(a)(1) and (a)(3) and §60.19. The proposed rule 

would also require the applicable recordkeeping requirements in 

subpart F of Part 75 to be met. For EGUs using CEMS, the data 

elements that would be recorded include, among others, hourly CO2

concentration, stack gas flow rate, stack gas moisture content 

(if needed), unit operating time, and gross electric generation. 

For EGUs that exclusively combust liquid and/or gaseous fuel(s) 

and elect to determine CO2 emissions using Equation G-4 in 

Appendix G of Part 75, the key data elements in subpart F that 
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would be recorded include hourly fuel flow rates, fuel usage 

times, fuel GCV, gross electric generation. 

The proposed rule would require EGU owners or operators to 

keep records of the calculations performed to determine the 

total CO2 mass emissions and gross output for each operating 

month. Records would be kept of the calculations performed to 

determine the average CO2 mass emission rate (kg/MWh) and the 

percentage of valid CO2 mass emission rates in each compliance 

period. The proposed rule would also require records to be kept 

of calculations performed to determine site-specific carbonbased F-factors for use in Equation G-4 of Part 75, Appendix G 

(if applicable). 

For EGU owners or operators who would elect to comply with 

the 60-operating-month rolling average emissions standard, 

records must be kept for 10 years. All other records would be 

kept for a period of three years. All required records would be 

kept on-site for a minimum of two years, after which the records 

could be maintained off-site. 

The proposed rule would require all affected EGU 

owners/operators to submit quarterly electronic emissions 

reports in accordance with subpart G of Part 75. The proposed 

rule would require these reports to be submitted using the ECMPS 

Client Tool. Except for a few EGUs that may be exempt from the 
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Acid Rain Program (e.g., oil-fired units), this is not a new 

reporting requirement. Sources subject to the Acid Rain Program 

are already required to report the hourly CO2 mass emission rates 

that are needed to assess compliance with today’s rule. 

Additionally, in the proposed rule and as part of an 

Agency-wide effort to streamline and facilitate the reporting of 

environmental data, the rule would require selected data 

elements that pertain to compliance under this rule, and that 

serve the purpose of traditional excess emissions reports, to be 

reported periodically using ECMPS. 

Specifically, for EGU owners/operators who would comply 

with a 12-operating-month rolling average standard, quarterly 

electronic “excess emissions” reports must be submitted, within 

30 days after the end of each quarter. The first report would be 

for the quarter that includes the final (12th) operating month of 

the initial 12 operating month compliance period. For that 

initial report and any subsequent report in which the twelfth 

operating month of a compliance period (or periods) occurs 

during the calendar quarter, the average CO2 mass emissions rate 

(kg/MWh) would be reported for each compliance period, along 

with the dates (year and month) of the first and twelfth 

operating months in the compliance period and the percentage of 

valid CO2 mass emission rates obtained in the compliance period. 
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The dates of the first and last operating months in the 

compliance period would clearly bracket the period used in the 

determination, which facilitates auditing of the data. Reporting 

the percentage of valid CO2 mass emission rates is necessary to 

demonstrate compliance with the requirement to obtain valid data 

for 95 percent of the operating hours in each compliance period. 

Any excess emissions that occur during the quarter would be 

identified. If there are no compliance periods that end in the 

quarter, a definitive statement to that effect would be included 

in the report. If one or more compliance periods end in the 

quarter but there are no excess emissions, a statement to that 

effect would be included in the report. 

For EGU owners or operators that would comply with a 60-

operating-month rolling average basis, quarterly electronic 

“excess emissions” reports would be submitted, within 30 days 

after the end of each quarter. The first report would be for the 

quarter that includes the final (60th) operating month of the 

initial 60-operating-month compliance period. For that initial 

report and any subsequent report in which the sixtieth operating 

month of a compliance period (or periods) occurs during the 

calendar quarter, the average CO2 mass emissions rate (kg/MWh) 

must be reported for each compliance period, along with the 

dates (year and month) of the first and sixtieth operating 
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months in the compliance period and the percentage of valid CO2

mass emission rates obtained in the compliance period. The dates 

of the first and last operating months in the compliance period 

would clearly bracket the period used in the determination, 

which facilitates auditing of the data. Reporting of the 

percentage of valid CO2 mass emission rates is necessary to 

demonstrate compliance with the requirement to obtain valid data 

for 95 percent of the operating hours in each compliance period. 

Any excess emissions that occur during the quarter would be 

identified. If there are no compliance periods that end in the 

quarter, a definitive statement to that effect would be included 

in the report. If one or more compliance periods end in the 

quarter but there are no excess emissions, a statement to that 

effect would be included in the report. 

Currently, ECMPS is not programmed to receive excess 

emission report information. However, we will make the necessary 

modifications to the system in order to fully implement the 

reporting requirements of this rule upon promulgation. 

IV. Rationale for Reliance on Rational Basis to Regulate GHGs 

from Fossil-fired EGUs

A. Overview

In our original proposal, we proposed and solicited comment 

on what basis we are required to have concerning the health and 

Comment [A50]: From any source category? Or, 

just from EGUs? Consider clarifying. 
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welfare impacts of GHG emissions from fossil-fuel fired power 

plants in order to regulate those emissions under CAA §111. 

However, we took the position that we are not required to make 

findings that GHGs from fossil-fired power plants “cause[], or 

contribute[] significantly to, air pollution which may 

reasonably be anticipated to endanger public health or welfare,” 

under CAA §111(b)(1)(A). 

We have reconsidered that proposal in light of the numerous 

comments we received. In today’s notice, we propose that the EPA 

has a rational basis for promulgating standards for GHG 

emissions from electricity generating plants because the EPA has 

already determined that GHG emissions may reasonably be 

anticipated to endanger public health and welfare; and 

electricity generating plants, as an industry, constitute, by a 

significant margin, the largest emitters in the inventory. In 

the April 2012 proposal, the EPA discussed whether CAA section 

111 requires that the EPA issue, as a prerequisite for this 

rulemaking, another “endangerment” finding. After reviewing the 

comments, recent scientific developments, the amount of 

emissions from the power plant sector, and the case law, the EPA 

has concluded that section 111 requires only that the EPA 

establish a rational basis for regulating GHG emissions from 

power plants, but that even if an endangerment finding were 
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required, the rational basis described in today’s action would 

qualify as an endangerment finding as well. 

As related matters, in this notice, we are proposing to 

establish regulatory requirements for CO2 emissions of affected 

units, which are included in a source category that the EPA 

already listed under CAA §111(b)(1)(A) for regulation under CAA 

and we are not proposing a new listing of a source category. We 

are, however, proposing to subcategorize different sets of 

sources, and establish different CO2 standards of performance for 

them, in accordance with CAA §111(b)(2). To avoid confusion, we 

are proposing to codify the CO2 standards of performance in the 

same subparts – Da and KKKK, depending on the types of units – 

that currently include the standards of performance for 

conventional pollutants, instead of codifying the CO2 standards 

in a new subpart.

B. Climate Change Impacts from GHG Emissions; Amounts of GHGs 

from fossil fuel-fired EGUs

In 2009, the EPA Administrator issued the Endangerment 

Finding under CAA section 202(a)(1). With the Endangerment 

Finding, the Administrator found that elevated concentrations of 

GHGs in the atmosphere may reasonably be anticipated to endanger 

public health and welfare of current and future generations, 

focused on public health and public welfare impacts within the 
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United States. Fossil fuel-fired EGUs are by far the largest 

emitters of GHGs, primarily in the form of CO2, among stationary 

sources in the U.S. These adverse effects of GHGs on public 

health and welfare, and the amounts of GHGs emitted by fossil 

fuel-fired EGUs are briefly summarized in the background section 

of this preamble, described in more detail in the RIA, and need 

not be recited here. 

C. CAA §111 requirements

To review the key CAA §111 requirements: CAA 

§111(b)(1)(A), by its terms, requires that the Administrator 

shall publish (and from time to time thereafter shall 

revise) a list of categories of stationary sources. He 

shall include a category of sources in such list if in 

his judgment it causes, or contributes significantly 

to air pollution which may reasonably be anticipated 

to endanger public health or welfare. 

CAA §111(b)(1)(B) goes on to provide that after listing the 

source category, the EPA must promulgate regulations 

“establishing federal standards of performance for new sources 

within such category.” In turn, CAA §111(a)(1) defines a 

“standard of performance” as a “standard for emissions of air 

pollutants which reflects the degree of emission reduction which 

(taking into account ... cost ... and any nonair quality health and 

environmental impact and energy requirements) ... has been 

adequately demonstrated.” CAA §111(b)(2) provides that “The 

Administrator may distinguish among classes, types, and sizes 
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within categories of new sources for the purpose of establishing 

such standards.” 

D. Interpretation of CAA §111 requirements

CAA §111(b)(1)(A) requires the EPA to list a source 

category if it contributes significantly to air pollution that 

endangers public health or welfare. The EPA must necessarily 

conduct this listing by making determinations as to the health 

or welfare impacts of one or more of the pollutants emitted by 

that source category, or the pollution to which the source 

category contributes and as to the significance of the amount of 

such contribution. However, by the terms of CAA §111(b)(1)(A), 

the EPA may make these determinations on the basis of the 

impacts of all of the source category’s pollutants taken as a 

whole. Nothing in CAA §111(b)(1)(A) requires that the EPA make 

separate determinations for each pollutant. 

After listing a source category, the EPA must proceed to 

promulgate standards of performance for the source category’s 

pollutants under CAA §111(b)(1)(B) and 111(a)(1). However, 

nothing in those provisions requires that, at the time when the 

EPA promulgates the standards of performance for the individual 

pollutants, the EPA must make a determination as to the health 

or welfare effects of those particular pollutants or as to the 

significance of the amount of the source category’s emissions of 
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those pollutants. Clearly, CAA §111 does not by its terms 

require that as a prerequisite for the EPA to promulgate a 

standard of performance for a particular pollutant, the EPA must 

first find that the pollutant causes or contributes 

significantly to air pollution that endangers public health or 

welfare. The lack of any such requirement contrasts with other 

CAA provisions that do require the EPA to make endangerment and 

cause-or-contribute findings for the particular pollutant that 

the EPA regulates under those provisions. E.g., CAA sections 

202(a)(1), 211(c)(1), 231(a)(2)(A). 

The lack of any express requirement in CAA section 111 

addressing whether and how the EPA is to evaluate emissions of a 

particular pollutant from the listed source category as a 

prerequisite for promulgation of a standard of performance is 

properly viewed as a statutory gap that requires the EPA to make 

what we refer to as a Chevron step 2 interpretation. Under the 

U.S. Supreme Court’s 1984 decision in Chevron U.S.A. Inc. v. 

NRDC,71 to interpret how a statute applies to a particular 

question, an agency must, at Step 1, determine whether 

Congress’s intent as to the specific question is clear, and, if 

so, the agency must give effect to that intent. If congressional 

intent is not clear, then the agency, at Step 2, has discretion 

 

71 467 U.S. 837 (1984). 
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to fashion an interpretation that is a reasonable construction 

of the statute.72 In this case, the EPA is authorized to develop 

a reasonable interpretation. 

Our interpretation is that in order to promulgate a §111 

standard of performance for a particular pollutant, we do not 

need to make a pollutant-specific endangerment finding, but 

instead must demonstrate a rational basis for controlling the 

emissions of the pollutant. That rational basis may be based on 

information concerning the health and welfare impacts of the air 

pollution at issue, and the amount of contribution that the 

source category’s emissions make to that air pollution. 

Commenters on the April 2012 proposal stated that the EPA 

is required to make an endangerment finding for CO2 because when 

the EPA listed this source category, it was on the basis of 

other pollutants, and not CO2. However, CAA §111(b)(1)(A) by its 

terms requires that the EPA “shall publish (and from time to 

time thereafter, shall revise) a list of categories of 

stationary sources,” and that the EPA shall list “a category of 

sources” based on the EPA’s judgment that the category “causes, 

or contributes significantly to, air pollution” that endangers 

public health or welfare. Thus, this provision requires that the 

EPA make the listing decision on a category basis, and not on a 

 

72 Id. at 842-43.
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pollutant-by-pollutant basis. That is, this provision does not 

require that the EPA establish separate lists of source 

categories, with each list covering a different pollutant. 

Therefore, this provision does not require that the EPA make an 

endangerment finding on a pollutant by pollutant basis. 

Commenters on the April 2012 proposal stated that the EPA 

was required to make an endangerment finding because by creating 

the new subpart TTTT in 40 CFR, the EPA was listing the source 

category that included the affected units. However, in neither 

the original proposal nor this new proposal has EPA proposed to 

list a new source category. The EPA initially included fossil 

fuel-fired EGUs (which includes EGUs that burn fossil fuel 

including coal, gas, oil and petroleum coke and that use 

different technologies, including boilers and combustion 

turbines) in a category that it listed under section 

111(b)(1)(A) and promulgated the first set of standards of 

performance for EGUs in 1971, codified in subpart D.73 

The EPA has revised those regulations, and in some 

instances, revised the subparts, several times over the ensuing 

decades. In 1979, the EPA divided subpart D into 3 subparts – Da 

 

73 “Standards of Performance for Fossil-Fuel-Fired Steam 

Generators for Which Construction Is Commenced After August 17, 

1971,” 36 Fed. Reg. 24875 (Dec. 23, 1971) codified at 40 CFR 

60.40-46; 36 Fed. Reg. 5931 (Mar. 31, 1971).
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(“Standards of Performance for Electric Utility Steam Generating 

Units for Which Construction is Commenced After September 18, 

1978”), Db (“Standards of Performance for Industrial-CommercialInstitutional Steam Generating Units”) and Dc (“Standards of 

Performance for Small Industrial-Commercial-Institutional Steam 

Generating Units”) – in order to codify separate requirements 

that it established for these subcategories.74 In 2006, the EPA 

created subpart KKKK, ”Standards of Performance for Stationary 

Combustion Turbines,” which applied to certain sources from 

multiple subparts.75 None of these rulemakings or codifications, 

however, constituted a new listing under CAA §111(b)(1)(A). 

In today’s rulemaking, similarly to the original proposal, 

the EPA is not proposing to list a new category of sources. 

Rather, the EPA is simply promulgating new standards of 

performance for CO2 emissions from certain sets of sources, e.g., 

boilers and turbines, but not liquid-fired sources. Moreover, we 

are establishing different requirements for different sets of 

sources, including smaller and larger combustion turbines, and 

boilers, in accordance with CAA §111(b)(2). That provision 

 

74 44 Fed. Reg. 33,580 (June 11, 1979) 

75 71 Fed. Reg. 38497 (July 6, 2006), as amended at 74 Fed. Reg. 

11861 (Mar. 20, 2009). 
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authorizes the EPA to “distinguish among classes, types, and 

sizes within categories of new sources for the purpose of 

establishing ... standards [of performance.]” 76

We recognize that our original proposal, by codifying these 

new standards of performance in a separate subpart, TTTT, may 

have led to some confusion over whether the new subpart under 

the EPA’s regulations constituted a new listing under CAA 

§111(b)(1)(A). That was not the case, for the reasons noted 

above, but to minimize confusion, we are taking a different 

approach in this proposal, and are codifying the new CO2

standards in the same subparts in which the standards of 

performance for conventional pollutants are codified. Thus, we 

are codifying the standards for solid-fuel fired EGUs as a new 

section in subpart Da, and the standards for turbines as new 

sections in subpart KKKK. 

E. Rational basis to promulgate standards for GHGs from fossilfired EGUs

In this rulemaking, the air pollution in question is GHGs, 

and the EPA has a rational basis for concluding that this air 

 

76 For this same reason, EPA’s notice today does not propose to 

revise the list. Though EPA in the April 2012 proposed rule 

preamble pointed to the authority to revise the list as a basis 

for the proposed rule, see 77 FR at 22398, upon further 

consideration EPA has concluded that our proposal does not 

constitute a revision to the list of categories for the reasons 

discussed above.
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pollution merits taking action under CAA §111. As noted, in 

2009, the EPA made a finding that GHG air pollution may 

reasonably be anticipated to endanger public health or welfare, 

and in 2010, the EPA denied petitions to reconsider that 

finding. The EPA extensively reviewed the available science 

concerning GHG pollution and its impacts in taking those 

actions. In 2012, the U.S. Court of Appeals for the D.C. Circuit 

upheld the finding and denial of petitions to reconsider. In 

addition, assessments from the NRC and the IPCC, published in 

2010, 2011, and 2012 lend further credence to the validity of 

the Endangerment Finding. As discussed below, no information 

that commenters have presented or that the EPA has reviewed 

provides a basis for rescinding that finding. In addition, as 

noted, the high level of GHG emissions from the fossil-fired 

EGUs makes clear that it is rational for the EPA to regulate GHG 

emissions from this sector. This information amply supports that 

the EPA has a rational basis for promulgating regulations under 

CAA §111 designed to address GHG air pollution. 

Our conclusion is consistent with the case law handed down 

by the D.C. Circuit. In its 1980 decision in National Lime 

Association v. EPA,77 the Court upheld EPA’s determination that 

lime manufacturing plants emit particulates that contribute 

 

77 627 F.2d 416 (D.C. Cir. 1980). 
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significantly to air pollution that endangers public health or 

welfare. The Court noted that (i) EPA’s basis was its prior 

determination that “the significant production of particulate 

emissions ... cause[s] or contribute[s] to air pollution (which 

may reasonably be anticipated to endanger public health or 

welfare);” and (ii) “[t]he Agency has made this determination 

for purposes of establishing national primary and secondary 

ambient air quality standards under [CAA §109].” The Court held: 

We think the danger of particulate emissions' effect 

on health has been sufficiently supported in the 

Agency's (and its predecessor's) previous 

determinations to provide a rational basis for the 

Administrator's finding in this case. 78

Similarly, in National Asphalt Pavement Ass’n v. Train,79 the 

D.C. Circuit upheld a determination by the EPA that asphalt 

cement plants contribute significantly to particulate matter air 

pollution that endangers public health and welfare. The Court 

indicated that the EPA’s determination that particulate matter 

endangers is valid simply on grounds that the EPA established a 

NAAQS for that pollutant.80

These cases support our relying primarily on the analysis 

and conclusions in our previous Endangerment Finding, and the 

subsequent assessments, as providing a rational basis for our 

 

78 Id. at 431-32 n.48. 79 539 F.2d 775 (D.C. Cir. 1976) 80 Id. at 784
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decision to impose standards of performance on GHG emissions 

from fossil-fuel fired EGUs. 

Commenters state that because the proposed rulemaking 

limits emissions of only CO2, and not other GHGs, the EPA cannot 

rely on the analysis and conclusions in the 2009 Endangerment 

Finding because it concerned a mix of six GHGs: carbon dioxide 

and five others. These commenters assert that as a prerequisite 

for the present rulemaking, the EPA must make an endangerment 

finding for CO2 alone. Commenters’ assertion here is incorrect 

for two reasons. First, as discussed above, the EPA does not 

need to make a formal endangerment finding with respect to a 

particular pollutant to set standards for that pollutant under 

section 111(b)(1)(B). Second, the EPA may reasonably rely on the 

analysis and conclusions in the 2009 Endangerment Finding on 

GHGs because, with respect to this proposed rulemaking, the air 

pollution at issue here is the mix of six GHGs. It is that air 

pollution that has caused the various impacts on health and 

welfare that formed the basis for the Endangerment Finding. 

Further, the CO2 emissions from EGUs cause or contribute 

significantly to that air pollution. As we noted in the 2009 

Endangerment Finding, CO2 is the “dominant anthropogenic 

Comment [A51]: This sentence is quite bulky. 

Consider whether the highlighted text could be 

deleted in this sentence, and then redrafted as a new 

sentence that follows the final clause in this 

sentence. In some way, this “Second,” sentence 

should be drafted to be more concise and 

straightforward. 
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greenhouse gas.”81 The fact that we are not regulating the other 

five GHGs in this rulemaking does not mean that we are required 

to identify the air pollution as CO2 rather than GHGs. This is 

consistent with the EPA past actions. In the 2010 Light Duty 

Vehicle Rule for which the Endangerment Finding served as the 

predicate, the EPA regulated only four of the GHGs, not all 

six.82 

Further, the fact that affected EGUs emit almost 1/3 of all 

U.S. GHGs and comprise by far the largest stationary source 

category of GHG emissions, as discussed above, provides a 

rational basis for regulating CO2 emissions from affected EGUs. 

Indeed, so great is the contribution of CO2 air pollutants from 

EGUs to GHG air pollution, that it is simply not necessary in 

this rulemaking to determine the specific threshold for when a 

contribution may be considered to be a “significant[]” 

contribution.83 There can be no question that whatever that 

threshold may be, GHG emissions from fossil-fuel fired EGUs 

 

81 [placeholder: Cite 82 [placeholder: Cite to Light Duty Vehicle Rule. 83 Commenters on the original proposal stated that new solid-fuel 

fired power plants made no contribution to air pollution because 

EPA’s modeling projected no new construction of those types of 

plants. However, CAA §111(b)(1)(A) is clear by its terms that 

the source category listing that is the prerequisite to 

regulation is based on the contribution of the “category” to air 

pollution, and therefore is not based on the contribution of 

only new sources in the category. 
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exceed it.84 This is consistent with previous EPA actions that 

have been upheld by the D.C. Circuit. In the National Lime 

Association v. EPA case, noted above, the Court upheld the EPA’s 

regulation of lime plants on grounds that they were one of the 

largest -- although not within the largest 10 percent -- 

emitting industries of particulates. The Court stated, 

EPA ... focused ...on the sheer quantity of dust generated 

by lime plants. 42 Fed.Reg. 22507 (“A study performed for 

EPA in 1975 by the Research Corporation of New England 

ranked the lime industry twenty-fifth on a list of 112 

stationary sources categories which are emitters of 

particulate matter”); SSEIS 8-2 (“In a study performed for 

EPA by Argonne National Laboratory in 1975, the lime 

industry ranked seventh on a list of the 56 largest 

particulate source categories in the U.S.”).85

In the National Asphalt Pavement Ass’n v. Train case, noted 

above, the Court upheld the EPA’s determination that the asphalt 

industry contributed significantly to the air pollution based on 

“the number of existing plants, the expected rate of growth in 

the number of plants, the rate of uncontrolled emissions, and 

the level of emissions currently tolerated.”86 

F. Alternative findings of endangerment and significant 

contribution

 

84 Indeed, it is literally true that if fossil-fuel fired EGUs 

cannot be found to contribute significantly to GHG air 

pollution, then there is no source category in the U.S. that 

does contribute significantly to GHG air pollution, a result 

that would defeat the purposes of CAA §111. 

85 627 F.2d at 432, n.48. 86 539 F.2d at 784-85.
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Even if CAA section 111 is interpreted to require that the 

EPA make endangerment and cause-or-contribute significantly 

findings as prerequisites for today’s rulemaking, then our 

rational basis, as described, should be considered to constitute 

those findings. 

As noted above, the EPA’s rational basis for regulating 

under §111 GHGs is based primarily on the analysis and 

conclusions in the EPA’s 2009 Endangerment Finding and 2010 

denial of petitions to reconsider that Finding, coupled with the 

2010, 2011, and 2012 assessments from the IPCC and NRC that 

describe scientific developments since those EPA actions. In 

addition, as noted above, we would review comments presenting 

other scientific information to determine whether that 

information has any meaningful impact on our primary basis. 

This rational basis approach is substantially similar to 

the approach the EPA took in the 2009 Endangerment Finding and 

the 2010 denial of petitions to reconsider. As noted, the D.C. 

Circuit upheld that approach in the CRR case. Accordingly, that 

approach would support an endangerment finding for this 

rulemaking. 

By the same token, if the EPA were required to make a 

cause-or-contribute-significantly finding for CO2 emissions from 

the fossil fuel-fired EGUs, as a prerequisite to regulating such 
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emissions under CAA §111, the same facts that support our 

rational basis determination would support such a finding. In 

particular, fossil fuel-fired EGUs emit almost 1/3 of all U.S. 

GHG emissions, and constitute by far the largest single 

stationary source category of GHG emissions. Thus, even if the 

EPA were required to make a cause-or-contribute-significantly 

finding as part of setting standards under section 111(b)(1)(B), 

it would not be necessary for the EPA to identify a specific 

threshold for the amount of emissions from a source category 

that constitutes a significant contribution. Under any 

reasonable threshold or definition, the emissions from EGUs are 

a significant contribution. 

G. Comments on the state of the science of climate change 

The EPA received a number of comments in response to the 

proposed NSPS rule that addressed the scientific underpinnings 

of the EPA’s 2009 Endangerment Finding and, in essence, the 

scientific justification for this rule. The EPA has carefully 

reviewed all of those comments, and responses to those comments 

are provided in the Response to Comments document for this 

action. It is important to place these comments in the context 

of the voluminous record on this subject that has been compiled 

over the last few years. This includes: 1) the process by which 

the Administrator reached the 2009 finding that GHGs are 
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reasonably anticipated to endanger the public health and welfare 

of current and future generations; 2) the EPA’s response in 2010 

to ten administrative petitions for reconsideration of the 

Endangerment Finding, the “Reconsideration Denial”; and, 3) the 

decision by the United States Court of Appeals for the DC 

Circuit (DC Circuit Court) in 2012 to uphold the Endangerment 

Finding and the Reconsideration Denial. 

As outlined in Section VIII.A. of the 2009 Endangerment 

Finding, the EPA’s approach to providing the technical and 

scientific information to inform the Administrator’s judgment 

regarding the question of whether GHGs endanger human health and 

welfare was to rely primarily upon the recent, major assessments 

by the U.S. Global Change Research Program (USGCRP), the 

Intergovernmental Panel on Climate Change (IPCC), and the 

National Research Council (NRC) of the National Academies. In 

brief, these assessments addressed the scientific issues that 

the EPA was required to examine, were comprehensive in their 

coverage of the GHG and climate change problem, and underwent 

rigorous and exacting peer review by the expert community, as 

well as rigorous levels of U.S. government review and 

acceptance, in which the EPA took part. The EPA received 

thousands of comments on the proposed Endangerment Finding and 

responded to them in depth in an 11-volume Response to Comments 
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(RTC) document. While the EPA gave careful consideration to all

of the scientific and technical information received, it placed 

less weight on the much smaller number of individual studies 

that were not considered or reflected in the major assessments—

often these studies were published after the submission deadline 

for those larger assessments. Primary reliance on the major 

scientific assessments provided the EPA greater assurance that 

it was basing its judgment on the best available, well-vetted 

science that reflected the consensus of the climate science 

community, rather than selecting the studies it would rely on. 

Nonetheless, the EPA reviewed individual studies not 

incorporated in the assessment literature to see if they would 

lead the EPA to change its interpretation of, or place less 

weight on, the major findings reflected in the assessment 

reports. From its review of individual studies submitted by 

commenters, the EPA concluded that these studies did not change 

the various conclusions or judgments the EPA would draw based on 

the more comprehensive assessment reports. The major findings of 

the USGCRP, IPCC, and NRC assessments supported the EPA’s 

determination that GHGs threaten the public health and welfare 

of current and future generations. The EPA demonstrated this 

scientific support at length in the Endangerment Finding itself, 
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in its Technical Support Document (which summarized the findings 

of USGCRP, IPCC and NRC), and in its RTC document. 

The EPA then reviewed ten administrative petitions for 

reconsideration of the Endangerment Finding in 2010. The 

Administrator denied those petitions in the “Reconsideration 

Denial” on the basis that the Petitioners failed to provide 

substantial support for the argument that the Endangerment 

Finding should be revised and therefore their objections were 

not of “central relevance” to the Finding.87 The EPA prepared an 

accompanying 3-volume Response to Petitions (RTP) document to 

provide additional information, often more technical in nature, 

in response to the arguments, claims, and assertions by the 

petitioners to reconsider the Endangerment Finding. 

The 2009 Endangerment Finding and the 2010 Reconsideration 

Denial were challenged in a lawsuit; on June 26, 2012, the DC 

Circuit Court upheld the Endangerment Finding and the 

Reconsideration Denial, ruling that the Finding was neither 

arbitrary nor capricious, was consistent with Massachusetts v. 

EPA,88 and was adequately supported by the administrative 

 

87 EPA’s Denial of the Petitions To Reconsider the Endangerment 

and Cause or Contribute Findings for Greenhouse Gases Under 

Section 202(a) of the Clean Air Act (“Reconsideration Denial”),

75 Fed. Reg. 49,556, 58 (Aug. 13, 2010).

88 Massachusetts v. EPA, 549 U.S. 497.
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record.89 The Court found that the EPA had based its decision on 

“substantial scientific evidence,”90 noted that the EPA’s 

reliance on assessments was consistent with the methods 

decision-makers often use to make a science-based judgment,91 and 

stated that “EPA’s interpretation of the governing CAA 

provisions is unambiguously correct.”92 The Court also found that 

the Petitioners had “not provided substantial support for their 

argument that the Endangerment Finding should be revised.”93 

Moreover, the Court assessed the EPA’s reliance on the major 

scientific assessment reports conducted by USGCRP, IPCC, and 

NRC, and subjected to rigorous expert and government review, and 

found that “EPA evaluated the processes used to develop the 

various assessment reports, reviewed their contents, and 

considered the depth of the scientific consensus the reports 

represented. Based on these evaluations, the EPA determined the 

assessments represented the best source material to use in 

deciding whether GHG emissions may be reasonably anticipated to 

endanger public health or welfare.”94 As the Court stated, “It 

makes no difference that much of the scientific evidence in 

 

89 Coalition for Responsible Regulation, Inc. v. EPA, 684 F.3d 

102 (D.C. Cir. 2012).

90 Ibid at 121. 91 Ibid at 120. 92 Ibid at 113. 93 Ibid at 125. 94 Ibid at 120.
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large part consisted of ‘syntheses’ of individual studies and 

research. Even individual studies and research papers often 

synthesize past work in an area and then build upon it. This is 

how science works. The EPA is not required to re-prove the 

existence of the atom every time it approaches a scientific 

question.”95 

It is within the context of this extensive record, and 

recent affirmation of the Endangerment Finding by the Court, 

that the EPA has considered all of the submitted science-related 

comments and reports for the April 2012 proposed rule, and will 

consider any further comments in response to today’s proposed 

rule. As it did in the original Endangerment Finding, the EPA is 

giving careful consideration to all of the scientific and 

technical information in the record. However, the major peerreviewed scientific assessments continue to provide the primary 

scientific and technical basis upon which the Administrator’s 

judgment relies regarding the threat to public health and 

welfare posed by GHGs. 

Commenters on the April 2012 proposed rule submitted two 

major peer-reviewed scientific assessments that were released 

since the administrative record concerning the Endangerment 

Finding was closed after the EPA’s 2010 Reconsideration Denial: 

 

95 Ibid at 120.
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the IPCC (2012) Special Report on Managing the Risks of Extreme 

Events and Disasters to Advance Climate Change Adaptation (SREX) 

and the NRC Report (2011) on Climate Stabilization Targets: 

Emissions, Concentrations, and Impacts over Decades to Millennia 

(2011). The EPA has reviewed these assessments and they are 

briefly characterized here: 

Special Report on Managing the Risks of Extreme Events and 

Disasters to Advance Climate Change Adaptation (SREX), 

Intergovernmental Panel on Climate Change, 2012. 

The IPCC SREX assessment states that, “A changing climate 

leads to changes in the frequency, intensity, spatial 

extent, duration, and timing of extreme weather and climate 

events, and can result in unprecedented extreme weather and 

climate events.” The SREX documents observational evidence 

of changes in some of the weather and climate extremes that 

have occurred globally since 1950. The SREX assessment also

provides evidence regarding the attribution of some of 

these changes to elevated concentrations of GHGs, including 

warming of extreme daily temperatures, intensification of 

extreme precipitation events, and rising extreme coastal 

high water due to increases in sea level. FurtherThe 

assessment notes that Ffurther increases in some extreme 

weather and climate events are projected over the 21st 

century. The assessments Combined also conclude that, 

combined with increasing vulnerability and exposure of 

populations and assets, changes in extreme weather and 

climate events have consequences for disaster risk, with 

particular impacts on the water, agriculture and food 

security, and health sectors. 

Report on Climate Stabilization Targets: Emissions, 

Concentrations, and Impacts over Decades to Millennia, 

National Research Council, 2011. 

The NRC Climate Stabilization Targets assessment states 

that, “Emissions of carbon dioxide from the burning of 

fossil fuels have ushered in a new epoch where human 

activities will largely determine the evolution of Earth’s 

climate. Because carbon dioxide in the atmosphere is long 

lived, it can effectively lock Earth and future generations 

into a range of impacts, some of which could become very 

Comment [A52]: Acronym for this assessment? 
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severe.” The assessment addresses the fact that emissions 

of carbon dioxide will alter the composition of the 

atmosphere, and therefore the climate, for thousands of 

years and attempts to quantify the implications of 

stabilizing GHG concentrations at different levels. The 

report also estimates a number of specific climate change 

impacts, finding warming could lead to increases in heavy 

rainfall and decreases in crop yields and Arctic sea ice 

extent, along with other important changes in precipitation 

and stream flow. For an increase in global average 

temperature of 1 to 2 oC above pre-industrial levels, the 

assessment found that the area burnt by wildfires in 

western North America will likely more than double and 

coral bleaching and erosion will increase due both to 

warming and ocean acidification; an increase of 3 oC will 

lead to a sea level rise of 1.6 to 3.3 feet by 2100; and 

with an increase of 4 oC, the average summer in the United 

States would be as warm as the warmest summers of the past 

century. The assessment notes that although many important 

aspects of climate change are difficult to quantify, the 

risk of adverse impacts is likely to increase with 

increasing temperature, and the risk of dangerous surprises 

can be expected to increase with the duration and magnitude 

of the warming. 

A number of other National Academy assessments regarding 

climate have also been released recently. The EPA has reviewed 

these assessments, and finds that the improved understanding of 

the climate system resulting from the two assessments described 

above and the other National Academy assessments strengthens the 

case that GHGs are endangering public health and welfare. 

Perhaps the most dramatic change relative to the prior 

assessments is that, where the previous 2007 IPCC AR4 assessment 

projected a rise in global sea level of between 7 and 23 inches 

by the end of the century relative to 1990 (with an 

acknowledgment that inclusion of ice sheet processes that were 

Comment [A53]: Add cites? 
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poorly understood would likely increase those projections), 

three new NRC assessments (Climate Stabilization Targets, 

National Security Implications for U.S. Naval Forces in 2011, 

and Sea Level Rise for the Coasts of California, Oregon, and 

Washington: Past, Present, and Future in 2012) have provided 

estimates of projected sea level rise that are twice as large or 

more. While the three NRC assessments continue to recognize and 

characterize the uncertainty inherent in accounting for ice 

sheet processes, these revised estimates strongly support and 

strengthen the existing finding that GHGs are reasonably 

anticipated to endanger human health and welfare. Other key 

findings of the recent assessments are described briefly below: 

The Sea Level Rise for the Coasts of California, 

Oregon, and Washington: Past, Present, and Future (2012) 

assessment notes that observations have shown that sea 

level rise on the West Coast has risen south of Cape 

Mendocino over the past century but dropped north of that 

point during that time due to tectonic uplift and other 

factors in Oregon and Washington. However, the assessment 

projects a global sea level rise of 1.6 to 4.6 feet by 

2100, which is sufficient to lead to rising relative sea 

level even in the northern states. The National Security 

Implications of Climate Change for U.S. Naval Forces also 

considers potential impacts of sea level rise, using a 

range of 1.3 to 6.6 feet by 2100. This assessment also 

suggests preparing for increased needs for humanitarian 

aid, responses to climate change in geopolitical hotspots 

including possible mass migrations, and addressing changing 

security needs in the Arctic as sea ice retreats. The 

Climate and Social Stress: Implications for Security 

Analysis (2012) assessment found that it would be “prudent 

for security analysts to expect climate surprises in the 

coming decade . . . and for them to become progressively 

more serious and more frequent thereafter[.]” Understanding 
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Earth’s Deep Past: Lessons for Our Climate Future (2011) 

examines the period of Earth’s history prior to the 

formation of the Antarctic and Greenland Ice Sheets because 

CO2 concentrations by the end of the century will have 

exceeded levels seen in the 30 million years since that 

time. The assessment discusses the possibility that 

analogous paleoclimate states might suggest higher climate 

sensitivity, less well regulated tropical surface 

temperatures, higher sea level rise, more anoxic oceans, 

and more potential for non-linear events such as the PaleoEocene Thermal Maximum than previously estimated. The 

assessment notes that three or four out of the five major 

coral reef crises of the past 500 million years were 

probably driven by acidification and warming caused by GHG 

increases similar to the changes expected over the next 

hundred years. The assessment states that “the magnitude 

and rate of the present greenhouse gas increase place the 

climate system in what could be one of the most severe 

increases in radiative forcing of the global climate system 

in Earth history.” Similarly, the Ocean Acidification: A 

National Strategy to Meet the Challenges of a Changing 

Ocean (2010) assessment found that “[t]he chemistry of the 

ocean is changing at an unprecedented rate and magnitude 

due to anthropogenic carbon dioxide emissions; the rate of 

change exceeds any known to have occurred for at least the 

past hundreds of thousands of years.” The assessment notes 

that the full range of consequences is still unknown, but 

the risks “threaten coral reefs, fisheries, protected 

species, and other natural resources of value to society.” 

Several commenters on the April 2012 proposed rule argue 

that the Endangerment Finding should be reconsidered or 

overturned based on those commenters’ reviews of specific 

climate science literature, particularly newer publications that 

have appeared since the EPA’s 2010 Denial of Petitions. Some 

commenters have presented their own compilations of individual 

studies as support for their assertions that climate change will 

have beneficial effects in many cases and that climate impacts 
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will not be as severe or adverse as the EPA and assessments like 

the USGCRP (2009) report have stated. These commenters conclude 

that U.S. society will continue to easily adapt to climate 

change and that climate change therefore does not pose a threat 

to human health and welfare. 

The EPA has reviewed the information submitted and finds 

that, the fundamental issues raised in the comments that 

critique the scientific justification for the rule have been 

addressed by either the EPA’s 11-volume response to comments for 

the 2009 Endangerment Finding, the EPA’s responses to all issues 

raised by Petitioners for the reconsideration of the 2009 

Endangerment Finding, or the D.C. Circuit Court in its 2012 

decision to uphold the EPA’s 2009 Endangerment Finding. The EPA 

has nonetheless carefully reviewed these comments and finds 

again that comments do not change the various conclusions or 

judgments that the EPA would draw based on the assessment 

reports relied upon in the recent 2009 Finding. 

These comments often highlight uncertainty regarding 

climate science as an argument for reconsideration. However, 

uncertainty was explicitly recognized in the 2009 Endangerment 

Finding: “The Administrator acknowledges that some aspects of 

climate change science and the projected impacts are more 
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certain than others”,96 and the decision to find endangerment was 

made with full recognition of the uncertainty involved. In 

addition, the D.C. Circuit Court decision noted that, “the 

existence of some uncertainty does not, without more, warrant 

invalidation of an endangerment finding.”97 In short, these 

recent publications submitted by commenters, and any new issues 

that are extracted from them, do not undermine either the 

significant body of scientific evidence that has accumulated 

over the years or the conclusions presented in the substantial 

peer-reviewed assessments of the USGCRP, NRC, and IPCC. 

Regarding the contentions that the U.S. will adapt to 

climate change impacts and that therefore climate change impacts 

pose no threat, the EPA stated in the 2009 Endangerment Finding, 

“Risk reduction through adaptation and GHG mitigation measures 

is of course a strong focal area of scientists and policy 

makers, including the EPA; however, the EPA considers adaptation 

and mitigation to be potential responses to endangerment, and as 

such has determined that they are outside the scope of the 

endangerment analysis.”98 The DC Circuit Court upheld this 

position, ruling that “These contentions [that the U.S. can 

 

96 74 FR 66524. 97 Coalition for Responsible Regulation, Inc. v. EPA, 684 F.3d 

121 (D.C. Cir. 2012).

98 74 FR 66512 (emphasis added).
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adapt] are foreclosed by the language of the statute and the 

Supreme Court's decision in Massachusetts v. EPA” because 

“predicting society’s adaptive response to the dangers or harms 

caused by climate change” does not inform the “scientific 

judgment” that the EPA is required to take regarding 

Endangerment.99 

Some commenters raise issues regarding the EPA Inspector 

General’s report, Procedural Review of EPA’s Greenhouse Gases 

Endangerment Finding Data Quality Processes. These commenters 

mischaracterize the report’s scope and conclusions and, thus, 

vastly overstate the significance of the Inspector General’s 

procedural recommendations. Ultimately, nothing in the Inspector 

General report questions the validity of the EPA’s Endangerment 

Finding because that report did not evaluate the scientific 

basis of the Endangerment Finding. Rather, the Inspector General 

offers recommendations for clarifying and standardizing internal 

procedures for documenting data quality and peer review 

processes when referencing existing peer reviewed science in the 

EPA actions. Unrelated to the endangerment finding and its 

validation by the Circuit Court, the EPA has made progress 

towards implementing the OIG recommendations. 

 

99 984 F.3d at 117. 
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One commenter submitted a number of emails from the period 

1999 to 2009 that were obtained from a University of East Anglia 

server in 2009 and publicly released in 2011. After reviewing 

these emails, the EPA finds that they raise no issues that were 

not previously raised by Petitioners in regard to an earlier 

group of emails from the same incident, released in 2009. The 

commenter makes unsubstantiated assumptions and subjective 

assertions regarding what the e-mails purport to show about the 

state of climate change science; this provides inadequate 

evidence to challenge the voluminous and well documented body of 

science that is the technical foundation of the Administrator’s 

Endangerment Finding. 

A number of comments were also submitted in support of the 

Endangerment Finding and/or providing further evidence that 

climate change is a threat to human health and welfare. A number 

of individual studies were submitted and a number of observed or 

projected climate changes of local importance or concern to 

commenters were documented. Again, the EPA places lesser weight 

on individual studies than on the major scientific assessments. 

Local observed changes can be of great concern to individuals 

and communities but must be assessed in the context of the 

broader science, as it is more difficult to draw robust 
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conclusions regarding climate change over short time scales and 

in small geographic regions.

V. Rationale for Applicability Requirements 

A. Applicability requirements - original proposal and comments

The original proposal was designed to apply to new 

intermediate and baseload EGUs, specifically, 1) fossil fuelfired boiler/steam turbines and IGCC EGUs subject to subpart Da 

for criteria pollutant emissions, and 2) combined cycle EGUs 

subject to subpart KKKK for criteria pollutant emissions. The 

original proposal explicitly did not apply to simple cycle 

turbines because we concluded that they were operated 

infrequently and therefore only contributed small amounts to 

total GHG emissions. (For convenience, we occasionally refer to 

this explicit statement that the proposed NSPS did not apply to 

a type of source as an exclusion). 

We received comments that supported the simple cycle 

exclusion and others that opposed it. Commenters in support 

stated that a new simple cycle power plant serves a different 

purpose than a new combined cycle plant and that economics will 

drive the use of combined cycle facilities over simple cycle 

plants. They also stated that the proposed standard is not 

achievable by, and therefore is not BSER for, simple cycle 

turbines. Commenters opposing the exclusion stated that it 
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creates an opportunity to evade the standard and could thereby 

increase GHG emissions. According to these commenters, any 

applicability distinctions should be based on utilization and 

function rather than purpose or technology. 

After considering these comments, we are proposing a 

different approach to the applicability provisions. 

B. Applicability requirements – today’s proposal

In today’s rulemaking, we propose that applicability should 

be based on electric sales alone, so that the proposed standards 

of performance apply to a facility if the facility sells more 

than 1/3 of its potential electric output and more than 219,000 

MWh net electric output to the grid. (We refer to a facility’s 

sale of more than one-third of its potential electric output as 

the 33 percent sales criterion, and we refer to the amount of 

potential electric output sold as the capacity factor.) This 

proposed definition does not explicitly exclude simple cycle 

combustion turbines, but as a practical matter, it would exclude 

most of them because the vast majority of simple cycle turbines 

sell less than 1/3 of their potential electric output. For 

combustion turbines that sell more than 1/3 of their potential 

electric output to the grid, we have concluded there are less 

expensive and lower emitting technologies that could be 

constructed consistent with today’s proposed standards. 

Comment [A54]: We would suggest adding a 

more clear justification for why EPA thinks this 

exclusion is needed. The description here seems to 

focus on why the exclusion was structured the way 

that it is versus why it is appropriate or what it is 

trying to achieve. 

Comment [A55]: Per year? 

Comment [A56]: Please add a description that 

indicates what, generally, the other 2/3 of electric 

output goes towards. 
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Although, as noted, today’s proposal does not explicitly exclude 

simple cycle combustion turbines, we solicit comment on whether 

to provide an explicit exclusion. 

We are proposing to apply the 33 percent sales criterion on 

a rolling three year basis instead of an annual basis for 

stationary combustion turbines for multiple reasons. First, 

extending the period to three years would permit facilities 

intended to generally operate at low capacity factors (e.g. 

simple cycle turbines that sell less than 1/3 of their potential 

electric output) to provide system capacity and operate at high 

capacity factors during individual years with abnormally high 

electric demand. Second, only 0.2 percent of existing simple 

cycle turbines had a three-year average capacity factor of 

greater than 33 percent between 2000 and 2012. Therefore, as 

noted, from a practical standpoint, few new simple cycle 

turbines be subjected to the standards of performance in this 

rulemaking. 

In addition, according to the AEO 2013 cost and performance 

characteristics for new generation technologies, advanced 

combined cycle facilities have a lower cost of electricity than 

advanced simple cycle turbine facilities above approximately a 

20 percent capacity factor. Therefore, the use of a combined 

cycle technology would be BSER for higher capacity factor 
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stationary combustion turbines. In addition, the 2013 AEO cost 

and performance characteristics for new generation technologies 

include costs for a conventional combined cycle facility. 

Advanced combined cycle facilities do not have a lower cost of 

electricity than conventional combined cycle facilities until 

above approximately a 40 percent capacity factor. Between 

approximately 20 to 40 percent capacity factors, conventional 

combined cycle facilities offer the lowest cost of electricity, 

and below approximately 20 percent capacity factors simple cycle 

turbines offer the lowest cost of electricity. A capacity factor 

exemption at 40 percent would allow combined cycle facilities 

built for low capacity factors to compete simple cycle turbines 

because neither would be subject to the NSPS requirements. Based 

on these cost considerations, we are specifically requesting 

comment on a range of 20 to 40 percent of potential electric 

output sales on a three-year basis for the capacity factor 

exemption. The lower range is consistent with generating the 

lowest cost of electricity for advanced combined cycle turbines, 

and based on historical capacity factors would impact the 

operation of only approximately two percent of simple cycle 

turbines. The upper range would be more consistent with the 

annual operational hour limitations in many simple cycle permits 

and would provide significant operational flexibility. 
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We are also requesting comments on whether applicability for 

stationary combustion turbines should be defined on a single 

calendar year basis, similar to the subpart Da applicability 

provisions, instead of a three-year basis. With a single year 

basis, we are considering an applicability level of 40 (instead 

of 33 percent) percent sales. Only 0.4 percent of existing 

simple cycle turbines had an annual capacity factor of greater 

than 40 percent between 2000 and 2012. Assuming the average 

hourly output of a simple cycle turbine is 80 percent of the 

maximum rated output, a simple cycle turbine could operate up to 

4,400 hours annually before exceeding the capacity factor 

threshold. This is consistent with the operation hour limitation 

in many permits. Therefore, with this 40 percent sales criterion 

on a single-year basis, as a practical matter, few new simple 

cycle turbines would be subject to the proposed standards of 

performance. We are specifically requesting comment on a range 

of 1/3 to 2/5 of potential electric output annual sales. The 

lower range would be consistent with how an EGU is currently 

defined in the EPA rules, and would mean that the proposed 

standards of performance would impact to approximately one 

percent of new simple cycle turbines. 

We are also proposing a different definition of potential 

electric output from the current definition in subpart Da. The 
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existing definition is based on the design heat input capacity 

and assumes a 33 percent net electric efficiency, regardless of 

the actual efficiency of the facility. This could potentially 

have a negative impact on more efficient facilities. For 

example, a 33 percent efficient 100 MW facility would have a 

potential electric output of 876,000 MWh and a 40 percent 

efficient 100 MW facility would have a potential electric output 

of only 723,000 MWh. This could potentially encourage the 

construction of less efficient facilities, since they could have 

a higher actual capacity factor than a more efficient unit, 

while still not being an EGU subject to a CO2 standard. 

Therefore, we are proposing a definition of potential electric 

output that allows the source the option of calculating its 

potential electric output on the basis of its actual design 

electric output efficiency on a net output basis, as an 

alternative to the default 33 percent value. 

The April 2012 proposal would have applied to facilities that 

primarily burn non-fossil fuels but also co-fire a fossil fuel. 

We have concluded that it is not appropriate to subject these 

facilities to the standards in today’s proposal. Therefore, we 

are proposing to limit the applicability of the standard to 

facilities where the heat input is comprised of more than 10.0 

percent fossil fuel on a three-year rolling average basis. This 

Comment [A57]: EPA should add more 

explanation of its rational for this determination. 
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approach is similar to that of the Mercury and Air Toxics 

Standards. To simplify determining applicability with the CO2

standard, we also request comment on whether the applicability 

for facilities that co-fire non-fossil fuels should be made on 

an annual average basis, instead of a three-year rolling average 

basis. 

In the original proposal, we requested comment on the 

applicability of the GHG NSPS to combined heat and power (CHP) 

facilities and if it should be changed from how it is currently 

determined in subpart Da. We have concluded that if CHP 

facilities meet the general applicability criteria they should 

be subject to the same requirements as electric-only generators. 

However, one potential issue that we have identified is 

inequitable applicability to third-party CHP developers compared 

to CHP facilities owned by the facility using the thermal output 

from the CHP facility. Third-party CHP developers would not have 

been able to benefit from the “minus purchased power on a 

calendar year basis” in the definition of net electric output 

when determining applicability since the thermal host(s) are not 

part of the same affected facility. We are therefore proposing 

to add “of the thermal host facility or facilities” to the 

definition of net-electric output for qualifying CHP facilities. 
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This would make applicability consistent for both facility-owned 

CHP and third-party-owned CHP. 

This proposal includes adding “any integrated device that 

provides electricity or useful thermal output to either the 

boiler/stationary combustion turbine or to power auxiliary 

equipment” in the definition of a steam electric generating 

unit, IGCC, and stationary combustion turbine in subparts Da and 

KKKK respectively. The rationale behind including integrated 

equipment is to avoid circumvention of the requirements by 

having a boiler not subject to the standard supplying useful 

energy input (e.g., for amine regeneration in a CCS system) 

without accounting for the GHG emissions, and to provide 

additional compliance flexibility. Even without this specific 

language, the original 1979 steam electric generating unit 

definition in subpart Da allows the use of solar thermal for 

feedwater heating as an approach to integrating non-emitting 

generation to reduce environmental impact and lower the overall 

emissions rate. The current definition expands the flexibility 

to include combustion turbines, fuel cells, or other combustion 

technology for reheating or preheating boiler feedwater, 

preheating combustion air, producing steam for use in the steam 

turbine or to power the boiler feedpumps, or using the exhaust 

directly in the boiler to generate steam. This in theory could 
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lower generation costs as well as lower the GHG emissions rate 

for an EGU. For example, using heat from integrated equipment to 

reheat boiler feedwater in a coal-fired EGU would minimize the 

steam otherwise extracted from the steam turbine used for the 

feedwater reheating process. This would decrease the size of the 

coal-fired boiler by approximately 1/4 for the same overall 

electric output, reducing the initial capital required to 

construct the new coal-fired portion of the EGU. Potential 

emission rate reductions are similar. While IGCC and NGCC do not 

extract the same levels of steam for feedwater heating 

requirements, multiple projects exist where solar thermal is 

integrated into the facility to preheat the feedwater and 

increase the output from the steam turbine relative to an NGCC 

facility without integrated solar thermal. Our understanding is 

that one of the primary benefits of this approach is decreased 

incremental cost of the solar thermal generated electricity due 

to the ability to use equipment (e.g., HRSG, steam turbine, 

condenser, etc.) already included at the NGCC facility. 

C. Codification in the Code of Federal Regulations

In the original proposal, the EPA proposed to create within 

40 CFR part 60 a new subpart that would include GHG emission 

regulatory requirements for electric utility steam generating 

units (i.e., boilers and IGCC units), whose conventional 
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pollutant regulatory requirements are codified under subpart Da; 

as well as stationary combustion turbines that generate 

electricity for sale and meet certain size and operational 

criteria, conventional pollutant regulatory requirements are 

codified under subpart KKKK. The EPA proposed to number this 

newly created subpart as subpart TTTT. The EPA explained that 

combining the GHG regulatory requirements for those sources in 

TTTT was appropriate because the EPA was establishing the same 

limit for all those sources based on the same BSER, which was 

NGCC. 

In today’s rulemaking, we propose different standards, 

based on different determinations of BSER, for (1) fossil fuelfired utility boilers and IGCC units, and (2) natural gas-fired 

stationary combustion turbines. In this manner, in accordance 

with CAA §111(b)(2), we are “distinguish[ing] among classes, 

types, and sizes within [the category of electric generating 

plants] of new sources for the purpose of establishing ... [the 

new source performance] standards.” As noted, to avoid 

confusion, we are codifying the new GHG regulatory requirements 

in the same subparts – Da and KKKK – that include the standards 

for conventional pollutants from those sources. Note that this 

codification does not increase the stringency of the NSPS 

requirements for criteria air pollutant emissions from those 
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sources, and thus does not affect the continued codification of 

those requirements in subparts Da and KKKK, as the case may be. 

VI. Legal Requirements for Establishing Emission Standards 

A. Overview

In this section, we describe the principal legal 

requirement for the standards of performance under CAA §111 that 

we propose in this rulemaking, which is that the standards must 

consist of emission limits that are based on the “best system of 

emission reduction ... adequately demonstrated,” taking into 

account cost and other factors. In this manner, CAA §111 

provides that the EPA’s central task is to identify the BSER. 

The D.C. Circuit has handed down case law, which we review in 

detail, that interprets this CAA provision, including its 

component elements. The Court’s interpretation indicates the 

technical, economic, and energy-related factors that are 

relevant for determining the BSER, and provides the framework 

for analyzing those factors. 

According to the D.C. Circuit, EPA determines the best 

demonstrated system based on the following key considerations, 

among others: 

 The system of emission reduction must be technically 

feasible. 

 EPA must consider the amount of emissions reductions that 
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the system would generate. 

 The costs of the system must be reasonable. EPA may 

consider the costs on the source level, the industry-wide 

level, and, at least in the case of the power sector, on 

the national level in terms of the overall costs of 

electricity and the impact on the national economy over 

time. 

 EPA must also consider that CAA §111 is designed to promote 

the development and implementation of technology. 

Other considerations are also important, including that EPA 

must also consider energy impacts, and, as with costs, may 

consider them on the source level and on the nationwide 

structure of the power sector over time. Importantly, EPA has 

discretion to weigh these various considerations, may determine 

that some merit greater weight than others, and may vary the 

weighting depending on the source category. 

B. CAA requirements and Court interpretation

1. Clean Air Act Requirements 

The EPA’s basis for proposing that partial capture CCS is 

the BSER for new fossil fuel-fired utility boilers and IGCC 

units, and that NGCC is the BSER for natural gas-fired 

stationary combustion turbines, is rooted in the provisions of 

Comment [A58]: This focuses on BSER instead 

of the standards of performance, but suggest that 

EPA consider referencing standards of performance 

here, especially since the next paragraph starts with 

that discussion. Or, consider stating that the basis of 

both the standards of performance and BSER are 

rooted in CAA 111 and caselaw. 
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CAA §111 requirements, as interpreted by the United States Court 

of Appeals for the D.C. Circuit (“D.C. Circuit” or “Court”), 

which is the federal Court of Appeals with jurisdiction over the 

EPA’s CAA rulemaking. 

As the first step towards establishing standards of 

performance, the EPA “shall publish ... a list of categories of 

stationary sources ... [that] cause[], or contribute[] 

significantly to, air pollution which may reasonably be 

anticipated to endanger public health or welfare.” 

§111(b)(1)(A). Following that listing, the EPA “shall publish 

proposed regulations, establishing federal standards of 

performance for new sources within such category” and then 

“promulgate ... such standards” within a year after proposal. 

§111(b)(1)(B). The EPA “may distinguish among classes, types, 

and sizes within categories of new sources for the purpose of 

establishing such standards.” §111(b)(2). The term “standard of 

performance” is defined to “mean[] a standard for emissions of 

air pollutants which reflects the degree of emission limitation 

achievable through the application of the best system of 

emission reduction which (taking into account the cost of 

achieving such reduction and any nonair quality health and 

environmental impact and energy requirements) the Administrator 

determines has been adequately demonstrated.” §111(a)(1). 
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2. Court interpretation 

For present purposes, the key §111 provisions are the 

definition of “standard of performance,” under CAA §111(a)(1), 

and, in particular, the “best system of emission reduction which 

(taking into account ... cost ... nonair quality health and 

environmental impact and energy requirements) ... has been 

adequately demonstrated.” The D.C. Circuit has reviewed 

rulemakings under §111 on numerous occasions during the past 40 

years, handing down decisions dated from 1973 to 2011,100 through 

which the Court has developed a body of case law that interprets 

the term “standard of performance.” These interpretations are of 

central importance to the EPA’s justification for the standards 

of performance in the present rulemaking. 

At the outset, it should be noted that Congress first 

included the definition of “standard of performance” when 

enacting CAA §111 in the 1970 Clean Air Act Amendments (CAAA), 

and then amended it in the 1977 CAAA, and then amended it again 

in the 1990 CAAA, generally repealing the amendments in the 1977 

CAAA and, therefore, reverting to the version as it read after 

 

100 Portland Cement Ass’n v. Ruckelshaus, 486 F.2d 375 (D.C. Cir. 

1973); Essex Chemical Corp. v. Ruckelshaus, 486 F.2d 427, (D.C. 

Cir. 1973); Portland Cement Ass’n v. EPA, 665 F.3d 177 (D.C. 

Cir. 2011).
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the 1970 CAAA. The legislative history for the 1970 and 1977 

CAAAs explained various aspects of the definition as it read at 

those times. Moreover, the various decisions of the D.C. Circuit 

interpreted the definition that was applicable to the 

rulemakings before the Court. Notwithstanding the amendments to 

the definition, the D.C. Circuit’s interpretations discussed 

below remain applicable to the current definition.101 

 

101 In the 1970 CAAA, Congress defined “standard of performance,” 

under §111(a)(1), as— 

a standard for emissions of air pollutants which 

reflects the degree of emission limitation achievable 

through the application of the best system of emission 

reduction which (taking into account the cost of 

achieving such reduction) the Administrator determines 

has been adequately demonstrated. 

In the 1977 CAAA, Congress revised the definition to 

distinguish among different types of sources, and to require 

that for fossil fuel-fired sources, the standard (i) be based 

on, in lieu of the “best system of emission reduction ... 

adequately demonstrated,” the “best technological system of 

continuous emission reduction ... adequately demonstrated;” and 

(ii) require a percentage reduction in emissions. In addition, 

in the 1977 CAAA, Congress expanded the parenthetical 

requirement that the Administrator consider the cost of 

achieving the reduction to also require the Administrator to 

consider “any nonair quality health and environment impact and 

energy requirements.” 

In the 1990 CAAA, Congress again revised the definition, 

this time repealing the requirements that the standard of 

performance be based on the best technological system and 

achieve a percentage reduction in emissions, and replacing those 

provisions with the terms used in the 1970 CAAA version of 

§111(a)(1) that the standard of performance be based on the 

“best system of emission reduction ... adequately demonstrated.” 

This 1990 CAAA version is the current definition, which is 
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3. Overview of interpretation 

By its terms, the definition of “standard of performance” 

under CAA § 111(a)(1) provides that the emission limit that the 

EPA promulgates must be “achievable” and must be based on a 

system of emission reduction – generally, but not required to be 

always, a technological control -- that the EPA determines to be 

the “best system” that is “adequately demonstrated,” “taking 

into account ... cost ... nonair quality health and environmental 

impact and energy requirements.” The D.C. Circuit has stated 

that in determining the “best” system, the EPA must also take 

into account “the amount of air pollution”102 and may take into 

account “technological innovation.”103

 As discussed below, the D.C. Circuit has elaborated on the 

criteria and process for determining whether a standard is 

“achievable,” based on an “adequately demonstrated” technology 

or system. In addition, the Court has identified limits on the 

costs and other factors that are acceptable for the technology 

or system to qualify as the “best.” The Court has also held that 

the EPA may consider the costs and other factors on a regional 

 

applicable at present. Even so, because parts of the definition 

as it read under the 1977 CAAA were retained in the 1990 CAAA, 

the explanation in the 1977 CAAA legislative history, and the 

interpretation in the case law, of those parts of the definition 

remain relevant to the definition as it reads today. 

102 See Sierra Club v. Costle, 657 F.2d 298, 326 (D.C. Cir. 1981). 103 See Sierra Club v. Costle, 657 F.2d at 347.
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or national level (e.g., the EPA may consider impacts on the 

national economy and the affected industry as a whole) and over 

time, and not just on a plant-specific level at the time of the 

rulemaking.104 In addition, the Court has emphasized that the EPA 

has a great deal of discretion in weighing the various factors 

to determine the “best system.”105 Moreover, the Court has 

stated that in considering the various factors and determining 

the “best system,” the EPA must be mindful of the purposes of 

§111, and the Court has identified those purposes as “not 

giv[ing] a competitive advantage to one State over another in 

attracting industry[,]... “reducing emissions as much as 

practicable[,]”... “forc[ing] the installation of all the control 

technology that will ever be necessary on new plants at the time 

of construction[,]...” and “forc[ing] the development of improved 

technology.”106 Finally, based on cases the D.C. Circuit has 

handed down under related provisions of the CAA and the EPA’s 

regulatory precedent under §111, the EPA may promulgate a 

standard of performance for a particular category of sources 

even if not every type of new source in the category would be 

 

104 See Sierra Club v. Costle, 657 F.2d at 330. 105 See Lignite Energy Council v. EPA, 198 F.3d 930, 933 (D.C. 

Cir. 1999). 

106 Sierra Club v. Costle, 657 F.2d at 325 & n.83 (quoting 44 

Fed.Reg. 33,580, 33,581/3-33,582/1). 
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able to achieve that standard.107 

We next discuss in more detail each of these components of 

the interpretation of “standard of performance.” 

C. Technical feasibility 

The D.C. Circuit’s first decision under §111, Portland 

Cement Ass’n v. Ruckelshaus, 486 F.2d 375, 391 (D.C. Cir. 1973), 

concerned whether EPA’s standard of performance for the cement 

industry met the requirement to be “achievable,” which, in turn, 

depended on whether the technology on which EPA based the 

standard was “adequately demonstrated.”108 In this case, the 

Court interpreted these provisions to require that the 

technology must be technically feasible for the source category, 

and established criteria for determining technical feasibility. 

The Court explained that a standard of performance is 

“achievable” if a technology can reasonably be projected to be 

available to new sources at the time they are constructed that 

will allow them to meet the standard. Specifically, the D.C. 

Circuit explained: 

Section 111 looks toward what may fairly be 

projected for the regulated future, rather than the 

state of the art at present, since it is addressed to 

standards for new plants....- It is the 

“achievability” of the proposed standard that is in 

 

107 See, e.g., International Harvester Co. v. EPA, 478 F.2d 615, 

640 (D.C. Cir. 1973). 

108 486 F.2d at 390.
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issue.... 

The Senate Report made clear that it did not 

intend that the technology “must be in actual routine 

use somewhere.” The essential question was rather 

whether the technology would be available for 

installation in new plants.... The Administrator may 

make a projection based on existing technology, though 

that projection is subject to the restraints of 

reasonableness and cannot be based on “crystal ball” 

inquiry.109

In subsequent cases, the D.C. Circuit has consistently 

reiterated this formulation of “achievable.”110 

 It should be noted that in another of the early cases, 

Essex Chemical Corp. v. Ruckelshaus, 486 F.2d 427 (D.C. Cir. 

1973), the D.C. Circuit upheld a standard of performance as 

“achievable” on the basis of test data showing that the tested 

plant emitted less than or at the standard on three occasions 

and emitted above the standard on 16 occasions, and that, on 

average, it emitted 15% above the standard on a total of 19 

occasions.111 The fact that the plant had achieved the standard 

on at least a few occasions, even though the plant had not done 

so on the great majority of occasions, “adequately demonstrated” 

that the standard was “achievable.” 

D. Factors to consider in determining the “best system” 

 

109 Portland Cement Ass’n v. Ruckelshaus, 486 F.2d 375, 391 (D.C. 

Cir. 1973) (citations omitted). 

110 See, e.g., National Asphalt Pavement Ass’n v. Train, 539 F.2d 775, 785 

(D.C. Cir. 1976); Lignite Energy Council v. EPA, 109 F//.3d 930, 934 (D.C. 

Cir. 1999). 

111 Essex Chemical Corp. v. Ruckelshaus, 486 F.2d at 437 & n. 27. 

Formatted: Highlight

Formatted: Highlight
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1. Amount of emissions reductions 

 Although the definition of “standard of performance” does 

not by its terms identify the amount of emissions from the 

category of sources and the amount of emission reductions 

achieved as factors the EPA must consider in determining the 

“best system of emission reduction,” the D.C. Circuit has stated 

that the EPA must do so. See Sierra Club v. Costle, 657 F.2d 

298, 326 (D.C. Cir. 1981) (“we can think of no sensible 

interpretation of the statutory words “best ... system” which 

would not incorporate the amount of air pollution as a relevant 

factor to be weighed when determining the optimal standard for 

controlling ... emissions”).112 

2. Costs 

In several cases, the D.C. Circuit has elaborated on the 

cost factor that the EPA is required to consider under CAA 

§111(a)(1), and has identified limits to how costly a control 

technology may be before it no longer qualifies as the “best 

system of emission reduction ... adequately demonstrated.” As a 

 

112 Sierra Club v. Costle, 657 F.2d 298 (D.C. Cir. 1981) was 

governed by the 1977 CAAA version of the definition of “standard 

of performance,” which revised the phrase “best system” to read, 

“best technological system.” The 1990 CAAA deleted 

“technological,” and thereby returned the phrase to how it read 

under the 1970 CAAA. The Sierra Club v. Costle’s interpretation 

of this phrase to require consideration of the amount of air 

emissions remains valid for the phrase “best system.” 
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related matter, although no D.C. Circuit case addresses how to 

account for revenue generated from the byproducts of pollution 

control, it is logical and a reasonable interpretation of the 

statute that the costs of the control technology should be 

offset by any revenues from the sale of pollutants or pollution 

control byproducts associated with those controls. Clearly, such 

a sale would offset regulatory costs and so must be included to 

accurately assess the costs of the standard. 

a. Criteria for costs 

(i) Formulation 

In Essex Chemical Corp. v. Ruckelshaus, 486 F.2d 427, 433 

(D.C. Cir. 1973), the D.C. Circuit stated that to be “adequately 

demonstrated,” the system must be “reasonably reliable, 

reasonably efficient, and ... reasonably expected to serve the 

interests of pollution control without becoming exorbitantly 

costly in an economic or environmental way.” The Court has 

reiterated this limit in subsequent case law, including Lignite 

Energy Council v. EPA, 198 F.3d 930, 933 (D.C. Cir. 1999), in 

which it stated: “EPA's choice will be sustained unless the 

environmental or economic costs of using the technology are 

exorbitant.” In Portland Cement Ass’n v. EPA, 513 F.2d 506, 508 

(D.C. Cir. 1975), the Court elaborated by explaining that the 

inquiry is whether the costs of the standard are “greater than 

Comment [A59]: Has this been done in any other 

NSPS context that could be referenced here? 
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the industry could bear and survive.” 

In Sierra Club v. Costle, 657 F.2d 298, 343 (D.C. Cir. 

1981), the Court provided a substantially similar formulation of 

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

Utilities' forecasted cost was not excessive and did not make 

the cost of compliance with the standard unreasonable. This is a 

judgment call with which we are not inclined to quarrel.” We 

believe that these various formulations of the cost standard – 

“exorbitant,” “greater than the industry could bear and 

survive,” “excessive,” and “unreasonable” – are synonymous; the 

D.C. Circuit has made no attempt to distinguish among them. For 

convenience, in this rulemaking, we will use the “unreasonable” 

formulation, so that a control technology cannot be considered 

the “best system of emission reduction ... adequately 

demonstrated” if its costs are “unreasonable.” 

 (ii) Examples 

In the case law under CAA §111, the D.C. Circuit has never 

invalidated a standard of performance on grounds that it was too 

costly. In several cases, the Court upheld standards that 

entailed high costs. In Portland Cement Association v. 

Ruckelshaus, 486 F.2d 375 (D.C. Cir. 1973), the Court considered 

a standard of performance that the EPA promulgated for 

particulate matter emissions from new and modified Portland 
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cement plants. According to the Court, the cost for the control 

technologies that a new facility would need to install to meet 

the standard was about 12 percent of the capital investment for 

the total facility, and annual operating costs for the control 

equipment would be 5-7 percent of the total plant operating 

costs. The Court found that these costs “could be passed on 

without substantially affecting competition” because the demand 

for the product was not “highly elastic with regard to price and 

would not be very sensitive to small price changes.” The Court 

held that the EPA gave appropriate consideration to the 

“economic costs to the industry.”113 

 In Sierra Club v. Costle, 657 F.2d 298 (D.C. Cir. 1981), 

the D.C. Circuit upheld a standard of performance imposing 

costly controls on SO2 emissions from coal-fired power plants. 

The Court noted: 

The importance of the challenged standards arises 

not only from the magnitude of the environmental and 

health interests involved, but also from the critical 

implications the new pollution controls have for the 

economy at the local and national levels. 

  

Coal is the dominant fuel used for generating 

electricity in the United States .... In 1976 power 

plant emissions accounted for 64 percent of the total 

estimated sulfur dioxide emissions and 24 percent of 

the total estimated particulate matter emissions in 

the entire country. 

 

113 Portland Cement Association v. Ruckelshaus, 486 F.2d at 387-

88. 

Comment [A60]: Is the case the same for EGUs? 

Add a FN to explain relevance. 
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EPA's revised NSPS are designed to curtail these 

emissions. EPA predicts that the new standards would 

reduce national sulfur dioxide emissions from new 

plants by 50 percent and national particulate matter 

emissions by 70 percent by 1995. The cost of the new 

controls, however, is substantial. EPA estimates that 

utilities will have to spend tens of billions of 

dollars by 1995 on pollution control under the new 

NSPS. Consumers will ultimately bear these costs, both 

directly in the form of residential utility bills, and 

indirectly in the form of higher consumer prices due 

to increased energy costs.114 

b. Revenue enhancements 

In determining, the costs of pollution control technology, 

it is reasonable to take into account any revenues generated by 

the sale of any by-products of the control process. Many types 

of pollution control technology generate byproducts that must be 

disposed, and the costs of that disposal are considered part of 

the costs of the control technology. For example, CCS generates 

a stream of CO2 that must be disposed of through sequestration. 

In some instances, however, the by-products of pollution 

control have marketable value. In these cases, revenues from 

selling the by-products would defray the costs of pollution 

control.115 For example, in a recent rulemaking under the CAA 

regional haze program that entailed determining the “best 

available retrofit technology” (BART) for power plants, revenue 

 

114 Sierra Club v. Costle, 657 F.2d at 313 (citations omitted) 

(emphasis added).

115 76 Fed. Reg. 58,570, 58,603/1-2 (September 21, 2011). 
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from fly ash generated during boiler combustion and sold for use 

in concrete production factored into the State’s selection of 

BART).116

3. Expanded use and development of technology 

In Sierra Club v. Costle, the Court made clear that 

technological innovation was grounded in the terms of section 

111 itself, and therefore should be considered one of the 

factors to be considered in determining the “best system of 

emission reduction:” 

Our interpretation of section 111(a) is that the 

mandated balancing of cost, energy, and nonair quality 

health and environmental factors embraces 

consideration of technological innovation as part of 

that balance. The statutory factors which EPA must 

weigh are broadly defined and include within their 

ambit subfactors such as technological innovation.117

 

As discussed below, CAA §111 standards can promote 

technological innovation through: (i) the expanded use of the 

technology that is considered to be the best demonstrated 

technology; (ii) the further development of the best 

 

116 Similarly, the EPA has taken into account the value of fuel 

savings in determining the costs of rules that limit emissions 

from motor vehicles, which limits manufacturers are expected to 

achieve by reducing the rates of fuel consumption by the 

vehicles. See, e.g., 77 Fed. Reg. 62,624, 62,628-29; 62,923-27; 

62,942-46 (October 15, 2012) (rulemaking setting GHG emissions 

standards for Light-Duty Vehicles for Model Years 2017-2025). 

117 Sierra Club v. Costle, 657 F.2d at 347. 

Comment [A61]: Add a citation to the State 

determination in the FN before sentence regarding 

EPA LDV rule. 
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demonstrated technology; and (iii) the development of technology 

that is emerging, but that is not necessarily on a path to 

become the best demonstrated technology. 

E. Nationwide component of factors in determining the “best 

system”

Another component of the D.C. Circuit’s interpretations of 

section 111 is that the EPA may consider the various factors it 

is required to balance on a national or regional level and over 

time, and not only on a plant-specific level at the time of the 

rulemaking.118 As the D.C. Circuit stated in Sierra Club v. 

Costle: 

The language of [the definition of ‘standard of 

performance’ in] section 111 ... gives EPA authority 

when determining the best ... system to weigh cost, 

energy, and environmental impacts in the broadest 

sense at the national and regional levels and over 

time as opposed to simply at the plant level in the 

immediate present.119 

In that case, in upholding the EPA’s variable standard for 

SO2 emissions, the D.C. Circuit justified and elaborated on that 

interpretation of the definition of “standard of performance;” 

and then went on to evaluate the EPA’s justification for its 

rulemaking in light of that interpretation. It is useful to set 

out these parts of the Court’s opinion at some length in order 

 

118 Sierra Club v. Costle, 657 F.2d at 351. 119 Sierra Club v. Costle, 657 F.2d at 330.

Comment [A62]: This last part doesn’t seem to 

be explained later. Discussion later talks about “the 

development of technology that is emerging.” 

Explanation of the “not necessarily on a path to 

become the best demonstrated technology” part 

would be helpful. 
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to make clear the scope of the factors and the nature of the 

balancing exercise that the Court held section 111(a)(1) 

authorizes the EPA to take. 

The Court first recited the terms of the definition of 

“standard of performance,” as it read following the 1977 CAA 

Amendments: 

The pertinent portion of section 111 reads: 

A standard of performance shall reflect the 

degree of emission limitation ... achievable through 

application of the best ... system of ... emission 

reduction which (taking into consideration the cost of 

achieving such emission reduction, any nonair quality 

health and environmental impact and energy 

requirements) the Administrator determines has been 

adequately demonstrated.120

The Court then stated that these terms could reasonably be 

read to authorize the EPA to establish the standard of 

performance based on environmental, economic, and energy 

considerations “on the grand scale:” 

Parsed, section 111 most reasonably seems to 

require that EPA identify the emission levels that are 

“achievable” with “adequately demonstrated 

technology.” After EPA makes this determination, it 

must exercise its discretion to choose an achievable 

emission level which represents the best balance of 

economic, environmental, and energy considerations. It 

 

120 Sierra Club v. Costle, 657 F.2d at 330. Note that the elipses 

in the quotation of the definition of “standard of performance” 

in the text indicate the omission of terms repealed by the 1990 

CAAA; the Court’s analysis of the meaning of this definition did 

not turn on those repealed terms, and as a result, the Court’s 

analysis remains relevant for the current definition of 

“standard of performance.” 
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follows that to exercise this discretion EPA must 

examine the effects of technology on the grand scale 

in order to decide which level of control is best. For 

example, an efficient water intensive technology 

capable of 95 percent removal efficiency might be 

“best” in the East where water is plentiful, but 

environmentally disastrous in the water-scarce West 

where a different technology, capable of only 80 

percent reduction efficiency might be “best.” ... The 

standard is, after all, a national standard with longterm effects.121

 

The Court then justified its “reading of ... section 111 as 

authorizing the EPA to balance long-term national and regional 

impacts of alternative standards” on the 1977 CAAA legislative 

history: 

The Conferees defined the best technology in 

terms of “long-term growth,” “long-term cost savings,” 

effects on the “coal market,” including prices and 

utilization of coal reserves, and “incentives for 

improved technology.” Indeed, the Reports from both 

Houses on the Senate and House bills illustrate very 

clearly that Congress itself was using a long-term 

lens with a broad focus on future costs, environmental 

and energy effects of different technological systems 

when it discussed section 111.122

 The Court then examined the EPA’s justification for the 

variable standard. The Court quoted at length the EPA’s 

 

121 Sierra Club v. Costle, 657 F.2d at 330 (emphasis added). As 

noted, after the 1990 CAAA -- which changed the term “best 

technological system ... of emission reduction ... adequately 

demonstrated” to “best system ... of emission reduction ... 

adequately demonstrated” -- the Court’s discussion of 

“adequately demonstrated technology” should be considered to 

hold true for adequately demonstrated system of emission 

reduction.

122 Sierra Club v. Costle, 657 F.2d at 331 (emphasis added) 

(citations omitted) (citing legislative history).
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discussion of how it “justified the variable standard in terms 

of the policies of the Act,” including, in part: 

The standard reflects a balance in environmental, 

economic, and energy consideration by being 

sufficiently stringent to bring about substantial 

reductions in SO2 emissions (3 million tons in 1995) 

yet does so at reasonable costs without significant 

energy penalties.... By achieving a balanced coal 

demand within the utility sector and by promoting the 

development of less expensive SO2 control technology, 

the final standard will expand environmentally 

acceptable energy supplies to existing power plants 

and industrial sources. 

By substantially reducing SO2 emissions, the 

standard will enhance the potential for long term 

economic growth at both the national and regional 

levels. 123

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

reasonable.124 

F. Overall purposes

The D.C. Circuit, during an extensive discussion of 

“standard of performance” in the 1981 decision in Sierra Club v. 

Costle, identified and explained the purposes of section 111 and 

upheld a standard in part on grounds that it was consistent with 

those purposes.125 Specifically, the D.C. Circuit identified “the 

essential purposes” of CAA §111 – insofar as relevant for 

 

123 Sierra Club v. Costle, 657 F.2d at 327-28 (quoting 44 Fed. 

Reg. at 33,583/3 - 33,584/1). 

124 Sierra Club v. Costle, 657 F.2d at 337-39. 125 Sierra Club v. Costle, 658 F.2d 298, 338-340 (D.C. Cir. 

1981). 

Comment [A63]: Elaborate this sentence or add 

another sentence to summarize the point you are 

trying to make here, which seems to be about EPA 

balancing factors on a national or regional level and 

over time (as opposed to about the fact that EPA 

selected a variable standard). The conclusion needs 

to be more robust to keep the reader oriented. 
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present purposes -- as follows: 126 

1. The standards must not give a competitive advantage 

to one State over another in attracting industry. 

2. The standards must maximize the potential for longterm economic growth by reducing emissions as much 

as practicable. This would increase the amount of 

industrial growth possible within the limits set by 

the air quality standards. 

3. The standards must to the extent practical force 

the installation of all the control technology that 

will ever be necessary on new plants at the time of 

construction when it is cheaper to install, thereby 

minimizing the need for retrofit in the future when 

air quality standards begin to set limits to 

growth. 

* * * * 

6. The standards should be stringent in order to force 

 

126 In Sierra Club v. Costle, the Court noted that during the 

course of the 1977 CAAA, the House-Senate Conference Committee 

added the percentage reduction requirement to the text of 

section 111, and, in the Conference Committee Report, explained 

that although EPA had the authority to establish a variable 

standard that reflected varying fuel characteristics, EPA could 

do so only after “finding that such a [variable standard] does 

not undermine the basic purposes of [section 111] and the other 

provisions of the [CAA]....” Sierra Club v. Costle, 657 F.2d at 

319 (citing H.R. Rep. No. 95-564, at 130 (1977)(Conf. Rep.), 

reprinted in 1977 U.S.C.C.A.N. 1077

 (1977 Conference Report)). The Court noted that those purposes 

were set forth in the legislative history, and went on to recite 

and then apply them. See Sierra Club v. Costle, 657 F.2d at 

325, 338-40. The variable standard at issue in that case is not 

directly relevant to the present rulemaking. Regardless, the 

purposes of section 111, as described by the Court, remain valid 

because they were valid under the 1977 CAAA, which, in relevant 

part, were not revised by the 1990 CAAA. If there is any 

question about that, then the purposes remain valid because the 

1977 House Committee Report grounded them in the 1970 CAAA, see

H.R. Rep. No. 95-294, 95th Cong., 1st Sess. 184-86 (1977) (1977 

House Comm. Rep.), and the 1990 CAAA changes to the definition 

of standard of performance had the effect of reinstating the 

definition as it read under the 1970 CAAA (with one addition, 

noted below). 
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the development of improved technology.127

These purposes merit further discussion here. 

1. No competitive advantage to any State 

 The first purpose for the standards, as quoted above – “not 

giv[ing] a competitive advantage to one State over another in 

attracting industry” – arose from Congress’s concern, expressed 

during the debates over the 1970 CAAA, that States had at least 

a short-term economic incentive to attract industry by limiting 

pollution controls, and that States with cleaner air quality 

would be positioned to do so. Congress designed section 111 to 

address that problem by requiring the EPA to establish 

nationwide emission limitations, which would apply regardless of 

any State’s air quality, and without giving advantage to any 

 

127 Sierra Club v. Costle, 657 F.2d at 325 & n.83 (quoting 44 

Fed. Reg. 33,580, 33,581/3-33,582/1 (EPA summary of the six 

purposes identified in the 1977 House Committee Report, H.R. 

Rep. No. 95-294, 95th Cong., 1st Sess. 184-86 (1977)) The Court 

identified two other purposes of §111: 

4 and 5. The standards to the extent practical must 

force new sources to burn high-sulfur fuel thus 

freeing low-sulfur fuel for use in existing sources 

where it is harder to control emissions and where lowsulfur fuel is needed for compliance. This will (1) 

allow old sources to operate longer and (2) expand 

environmentally acceptable energy supplies. 

Id. (quoting 44 Fed.Reg. 33,580, 33,581/3-33,582/1). These 

purposes are not relevant to the present rulemaking and, in 

any event, following the repeal in the 1990 CAAA of the 

percentage reduction requirements of the 1977 version of 

section 111, are no longer good law.
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state.128 This does not mean that certain States would not retain 

certain inherent advantages – such as resource availability - 

over other States in attracting certain industries. For example, 

coal-fired power plants need large quantities of coal and water 

to operate, and States with those resources are more likely to 

attract that industry than States without those resources. In 

Congress’s view, what was important was that the section 111 

standards themselves be uniform on a nationwide basis. 

2. Maximum practicable emissions reductions 

 The second and third purposes for the standards are, as 

quoted above, “reducing emissions as much as practicable” and 

“forc[ing] the installation of all the control technology that 

will ever be necessary at the time of construction.” These 

purposes apply to all pollutants that are subject to section 

111, including greenhouse gases. 

Section 111 applies by its terms to a range of pollutants. 

For example, CAA §111(d)(1)(A), which applies to existing 

sources, references National Ambient Air Quality Standards 

(NAAQS) pollutants that EPA lists by rule under CAA § 108, air 

toxics that are listed under CAA § 112, and any other type of 

air pollutant. The U.S. Supreme Court has made it clear that CAA 

§111 applies to GHGs because (i) §111 applies to “air 

 

128 See S. Rep. 91-1196 at 16 (1970 Senate Committee Report)),.
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pollutants,” CAA §§111(a)(1), 111(d)(1)(A), and in Massachusetts 

v. EPA, 549 U.S. 497 (2007), the Supreme Court held that this 

term includes GHGs; and (ii) in American Electric Power Company 

v. Connecticut, 131 S.Ct. 2527 (2011), the Supreme Court based 

its holding that “the Clean Air Act and the EPA actions it 

authorizes displace any federal common law right to seek 

abatement of carbon-dioxide emissions from fossil fuel-fired 

power plants” on the grounds that CAA section 111 “provides a 

means to seek limits on emissions of carbon dioxide from 

domestic power plants....”129

The legislative history of CAA §111 and the D.C. Court have 

articulated these purposes of reducing emissions and forcing the 

up-front installation of technology so that they apply to all 

pollutants subject to CAA §111. 

The 1977 House Committee Report noted, “In the [1970] 

Congress [sic: Congress’s] view, it was only right that the 

costs of applying best practicable control technology be 

considered by the owner of a large new source of pollution as a 

normal and proper expense of doing business.”130 Similarly, the 

1970 Senate Committee Report stated: 

The implicit consideration of economic factors in 

determining whether technology is “available” should 

 

129 American Electric Power, 131 S.Ct. at 2538. 130 1977 House Committee Report at 184. 
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not affect the usefulness of this section. The 

overriding purpose of this section would be to prevent 

new air pollution problems, and toward that end, 

maximum feasible control of new sources at the time of 

their construction is seen by the committee as the 

most effective and, in the long run, the least 

expensive approach.131

The D.C. Circuit, in Essex Chemical Corp. v. Ruckelshaus, 

486 F.2d 427 (D.C. Cir. 1973) cited the legislative history in 

stating that it was necessary to “[k]eep[] in mind Congress' 

intent that new plants be controlled to the ‘maximum practicable 

degree.’”132 Thus, a section 111 standard of performance 

controlling GHGs must be evaluated in light of the congressional 

purposes of “reducing emissions as much as practicable” and 

“forc[ing] the installation of all the control technology that 

ever will be necessary ... at the time of construction.” In fact, 

these purposes seem particularly important in the case of 

standards for coal-fired power plants because (i) these plants 

are the largest emitters of CO2 and, as a result, provide the 

most important opportunity for controlling emissions; and (ii) 

new power plants have expected lifetimes of as long as 50 years 

and possibly longer. 

3. Technology forcing 

 

131 S. Comm. Rep. No. 91-1196 at 16. 132 Essex Chemical Corp. v. Ruckelshaus, 486 F.2d at 437 & n. 27 

(citing Summary of the Provisions of Conference Agreement on the 

Clean Air Amendments of 1970, 116 Cong. Rec. 42384, 42385 

(1970)). 

Comment [A64]: EPA may want to consider 

reiterating this point and citation (copied below) 

from earlier about how section 111 looks towards 

what may be fairly projected, which is not clear from 

the case law cited in this section. 

The Court explained that a standard 

of performance is “achievable” if a 

technology can reasonably be 

projected to be available to new 

sources at the time they are 

constructed that will allow them to 

meet the standard. Specifically, 

the D.C. Circuit explained: 

Section 111 looks toward what 

may fairly be projected for the 

regulated future, rather than 

the state of the art at 

present, since it is addressed 

to standards for new 

plants....- It is the 

“achievability” of the proposed 

standard that is in issue.... 

The Senate Report made clear 

that it did not intend that the 

technology “must be in actual 

routine use somewhere.” The 

essential question was rather 

whether the technology would be 

available for installation in 

new plants.... The 

Administrator may make a 

projection based on existing 

technology, though that 

projection is subject to the 

restraints of reasonableness 

and cannot be based on “crystal 

ball” inquiry.1
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 The last purpose the D.C. Circuit in Sierra Club v. Costle

stated – “[t]he standards should be stringent in order to force 

the development of improved technology” – was based on the 1977 

House Committee Report.133 The full statement in that report 

provides a more robust articulation of Congress’s purposes: 

[T]he best technology requirement was intended to 

create incentives for improved technology, which could 

achieve greater or equivalent emission reduction at 

equivalent or lower cost, energy demand, and 

environmental impacts. This was to be accomplished by 

assuring any vendor who produced such an improved 

technological system that the standards would be 

revised to reflect that improvement, and a guaranteed 

market for the technology would thereby be created.134

According to the House Committee Report, this statement 

describes the purposes of the 1970 CAAA, and it is clearly 

consistent with other statements in the 1970 CAAA legislative 

history. For example, the 1970 Senate Committee Report stated: 

Standards of performance should provide an 

incentive for industries to work toward constant 

improvement in techniques for preventing and 

controlling emissions from stationary sources, since 

more effective emission control will provide greater 

latitude in the selection of sites for new 

facilities.135

 

133 Sierra Club v. Costle, 657 F.2d at 325 & n.83 (quoting 44 

Fed.Reg. 33,580, 33,581/3-33,582/1 (EPA summary of the six 

purposes identified in the 1977 House Committee Report, H.R. 

Rep. No. 95-294, 95th Cong., 1st Sess. 184-86 (1977)) 

134 1977 H. Comm. Rep. at 184-86 (GLH at 2651-53) 135 S.Rep. 91-1196 at 16 (1970). The technology-forcing nature of 

§111 is consistent with the technology-forcing nature of the 

1970 CAAA as a whole. The principal Senate author of the 1970 

CAAA, Sen. Edmund Muskie (D-ME), during the Senate floor debate, 

Comment [A65]: On its own, couldn’t this be 

read to mean that 111 incentivizes new technologies 

through a process where a vendor produces a new 

innovation and then the standard moves up to that 

level of performance (rewarding the vendor by then 

guaranteeing a market) vs. being “forcing” in the 

sense that it sets a forward looking standard that 

vendors must then meet? For this reason, it may be 

helpful to consider reiterating here the case law 

supporting a reading that 111 looks towards what 

may be fairly projected (see previous comment). 
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Similarly, the 1977 Senate Committee Report stated: 

 In passing the Clean Air Amendments of 1970, the 

Congress for the first time imposed a requirement for 

specified levels of control technology. The section 

111 Standards of Performance for New Stationary 

Sources required the use of the “best system of 

emission reduction which (taking into account the cost 

of achieving such reduction) the Administrator 

determines has been adequately demonstrated.” This 

requirement sought to assure the use of available 

technology and to stimulate the development of new 

technology.136

The legislative history just quoted identifies three 

different ways that Congress designed section 111 to authorize 

standards of performance that promote technological improvement: 

 

described the overall requirements of the 1970 and then 

observed: 

These five sets of requirements will be difficult 

to meet. But the committee is convinced that industry 

can make compliance with them possible or impossible. 

It is completely within their control. Industry has 

been presented with challenges in the past that seemed 

impossible to meet, but has been made possible. 

. 

136 S. Rep. 95-127 at 17 (1977), cited in Sierra Club v. Costle, 

657 F.2d at 346 n. 174. The 1977 CAAA legislative history is 

replete with other references to the technology forcing nature 

of §111 or the CAAA as a whole. See 1977 Clean Air Act 

Conference Report: Statement of Intent; Clarification of Select 

Provisions, 123 Cong. Rec. 27071 (1977) (quoted in Sierra Club 

v. Costle, 657 F.2d at 346 n. 174) (one of the enumerated 

purposes of section 111 was to “create incentives for new 

technology”); __ Cong. Reg. __ (May 24, 1977) (statement of Rep. 

Meads) (”The main purposes of the Clean Air Act Amendments of 

1977 are as follows: ... tenth, to promote the utilization of new 

technologies for pollution choice”). 
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(i) the development of technology that may be treated as the 

“best system of emission reduction ... adequately demonstrated;” 

under section 111(a)(1)137; (ii) the expanded use of the best 

demonstrated technology;138 and (iii) the development of emerging 

technology.139

G. Chevron framework

Above, we discuss how in Sierra Club v. Costle the D.C. 

Circuit interpreted the definition of “standard of performance” 

in CAA §111(a)(1), among other things, to authorize the EPA to 

balance economic, environmental, or energy factors through a 

nationwide lens, and to encompass technology forcing. The D.C. 

Circuit handed down this decision in 1981, and therefore it did 

not employ the two-step framework for statutory construction in 

federal rulemaking that the U.S. Supreme Court mandated in 1984, 

in Chevron U.S.A. Inc. v. NRDC, 467 U.S. 837 (1984). However, 

the D.C. Circuit’s interpretations are fully consistent with the 

 

137 See Portland Cement Ass’n v.Ruckelshaus, 486 F.2d 375, 391 

(D.C. Cir. 1973) (the best system of emission reduction must 

“look[] toward what may fairly be projected for the regulated 

future, rather than the state of the art at present”). 

138 See 1970 Senate Committee Report No. 91-1196 at 15, GLH 

at 415 (“The maximum use of available means of preventing 

and controlling air pollution is essential to the 

elimination of new pollution problems”). 

139 See Sierra Club v. Costle, 657 F.2d at 351 (upholding a 

standard of performance designed to promote the use of an 

emerging technology). 

. 
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Chevron framework. 

In Chevron, the Supreme Court held that an agency must, at 

Step 1, determine whether Congress’s intent as to the specific 

matter at issue is clear, and, if so, the agency must give 

effect to that intent. If congressional intent is not clear, 

then, at Step 2, the agency has discretion to fashion an 

interpretation that is a reasonable construction of the 

statute.140 

As noted, under CAA section 111(a)(1), a standard of 

performance must be based on the “best system of emission 

reduction which (taking into account the cost of achieving such 

reduction and any nonair quality health and environmental impact 

and energy requirements) ... has been adequately demonstrated.” 

The terms “best system of emission reduction,” “cost,” and 

“energy requirements,” on their face, can be interpreted to 

apply on a regionwide or nationwide basis, and are not limited 

to the individual source. Thus, this interpretation is 

supportable under Chevron step 1, but even if not, then the EPA 

considers the interpretation supportable under step 2 because it 

is reasonable and consistent with the purposes of the CAA. 

Similarly, the technology-development interpretation is 

supportable under Chevron step 1 because encouraging the 

 

140 Chevron U.S.A. Inc. v. NRDC, 467 U.S. 837, 842-43 (1984). 
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utilization or development of improved technology is selfevidently a consideration in determining the “best system of 

emission reduction” and was clearly a focus of the legislative 

history141, but even if that interpretation is not supportable 

under Chevron step 1, then the EPA considers the interpretation 

supportable under step 2 because it is reasonable and consistent 

with the purposes of the CAA.

H. Agency discretion 

The D.C. Circuit has made clear that the EPA has broad 

discretion in determining the appropriate standard of 

performance under the definition in CAA §111(a)(1), quoted 

above. Specifically, in Sierra Club v. Costle, 657 F.2d 298 

(D.C. Cir. 1981), the Court explained that “section 111(a) 

explicitly instructs the EPA to balance multiple concerns when 

promulgating a NSPS,”142 and emphasized that “[t]he text gives 

the EPA broad discretion to weigh different factors in setting 

the standard.”143 In Lignite Energy Council v. EPA, 198 F.3d 930 

(D.C. Cir. 1999), the Court reiterated: 

Because section 111 does not set forth the weight 

that should be assigned to each of these factors, we 

have granted the agency a great degree of discretion 

in balancing them.... EPA's choice [of the ‘best 

system’] will be sustained unless the environmental or 

 

141 [D.C. Circuit Chevron step 1 case citing legislative history.] 142 Sierra Club v. Costle, 657 F.2d at 319. 143 Sierra Club v. Costle, 657 F.2d at 321.
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economic costs of using the technology are 

exorbitant.... EPA [has] considerable discretion under 

section 111.144 

The important point is that Courts acknowledge that there 

are several factors to be considered and what is “best” depends 

on how much weight to give the factors. In promulgating certain 

standards of performance, EPA may give greater weight to 

particular factors than it may do so in promulgating other 

standards of performance. Thus, the determination of what is 

“best” is complex and necessarily requires an exercise of 

judgement. By analogy, the question of who is the “best” 

sprinter in the 100-meter dash primarily depends on only one 

criterion – speed – and therefore is relatively straightforward, 

while the question of who is the “best” baseball player depends 

on a more complex weighing of several criteria and therefore 

requires a greater exercise of judgment. 

I. Lack of requirement that standard be able to be met by all 

sources

 Under CAA §111, an emissions standard may meet the 

requirements of a “standard of performance” even if it cannot be 

met by every new source in the source category that would have 

constructed in the absence of that standard. As discussed below, 

 

144 Lignite Energy Council v. EPA, 198 F.3d 930, 933 (D.C. Cir. 

1999) (paragraphing revised for convenience). 

Comment [A66]: Suggest this is not necessary. 
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this is clear in light of (i) the legislative history of CAA 

§111, read in conjunction with the legislative history of the 

CAA as a whole; (ii) case law under analogous CAA provisions; 

and (iii) long-standing precedent in the EPA rulemakings under 

CAA §111.1. 

As noted, Congress, in enacting section 111 in the 1970 

CAAA, intended that the EPA promulgate uniform, nationwide 

controls. Congress was explicit that this meant that large 

industrial sources, including electric generating power plants, 

would be required to implement controls meeting the requirements 

regardless of their location. According to the 1970 Senate 

Committee Report: 

Major new facilities such as electric generating 

plants, kraft pulp mills, petroleum refineries, steel 

mills, primary smelting plants, and various other 

commercial and industrial operations must be 

controlled to the maximum practicable degree 

regardless of their location and industrial 

operations....145

Congress’s purposes in designing a standard that called for 

uniform national controls were to prevent pollution havens – 

caused by some states seeking competitive advantage by limiting 

their pollution control requirements – and to assure that areas 

that had good air quality would be able to maintain good air 

quality even after new industrial sources located there, which, 

 

145 1970 S. Comm. Rep. at 16, GLH at 416. See 1970 Senate Debate 

on Conference, 91 Cong. Rec. 42,384 (Muskie)?? 

Comment [A67]: Note citation has question 

marks that need to be resolved. 
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in turn, would allow more sources to locate there as well.146

 At the same time, Congress recognized that in light of the 

attainment provisions of the CAAA of 1970, sources – 

particularly large industrial sources, again, including electric 

generating plants -- may not be able to construct new facilities 

anywhere in the country; that is, an area with air quality at or 

above the NAAQS limits might not have enough room in its airshed 

to accommodate these new facilities. The 1970 Senate Committee 

Report stated, “[l]and use policies must be developed to prevent 

location of facilities which are not compatible with 

implementation of national standards.”147 Senator Muskie added: 

Land use planning and control should be used by State, 

local, and regional agencies as a method of minimizing 

air pollution. Large industries and power generating 

facilities should be located in places where their 

adverse effect on the air is minimal. There is a need 

for State or regional agencies to revise proposed 

power plant sites to assure that a number of 

environmental values, including air pollution, are 

considered.148

The 1970 CAAA legislative history includes other statements that 

also recognize that under the newly required air pollution 

control requirements, new sources may not be able to build 

anywhere in the country and, in fact, some existing sources 

 

146 See S. Comm. Rep. at 16, GLH at 416. 147 1970 Sen. Comm. Rep, 91-1196 (91st Cong., 2d Sess) p. 2: 148 1970 Senate Debate, GLH at 37 (Sept. 21, 1970) (statement of 

Sen. ?? Muskie?/] maybe p. 32,917. 
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might have to be shut down.149 At the time, Congress expected 

that local air quality concerns would be the reason why some 

sources would not be able to locate in certain places.

ThusIThus, in 1970, Congress designed section 111 to 

require uniform national controls for large industrial 

facilities, while recognizing that those facilities could not 

necessarily construct in every place in the country. Although at 

the time, Congress expected that local air quality concerns 

would be the reason why some sources would not be able to locate 

in certain places, Thus, if for any reason, if the reason it 

turns out that sources are not able to locate in certain places 

because of the air pollution control requirements, to be related 

to the emission limits that the EPA promulgates under section 

111,that such action should not be viewed as inconsistent with 

section 111. For example, if the EPA promulgates section 111 

emission limits based on a particular type of technology, and 

for economic or technical reasons, sources are able to utilize 

that technology in only certain parts of the country and not 

other parts, that result should not be viewed as inconsistent 

with congressional intent under CAA section 111. Rather, that 

result is consistent with Congress’s recognition that certain 

sources may be precluded from locating in certain areas. 

 

149 [cites]

Comment [A68]: Moved to paragraph discussing 

legislative history. 

Comment [A69]: Suggested edits for 

consideration. 
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2. Case law under analogous CAA provisions 

 Under analogous CAA provisions, the D.C. Circuit has 

recognized that the EPA may promulgate uniform standards that 

apply to new sources in a group or category of sources, even 

though some types of those new sources that would otherwise 

construct would no longer be able to construct because they 

could not meet the standard. One of these cases was 

International Harvester Co. v. EPA, 478 F.2d 615 (D.C. Cir. 

1973). There, the EPA declined to exercise its discretion under 

the CAA mobile source provisions, as they read at that time (42 

USC 1857f-1(b)(5)(D) (1970 CAAA)), to grant automakers a oneyear extension to comply with exhaust standards. The EPA stated 

that the automakers had failed to meet their burden of 

establishing that controls were not available. The EPA based its 

decision on grounds that certain technology was available for 

the motor vehicles in question. The EPA dismissed the 

automakers’ objections that this technology could not feasibly 

be installed in all models or engine types, and the EPA 

explained that the public’s “basic demand” for automobiles could 

be met by the models and engine types that could feasibly 

install that technology. 478 F.2d at 626. 

Although the Court remanded the EPA’s decision not to grant 

the one-year extension, it agreed with the EPA on this point, 
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stating: 

We are inclined to agree with the Administrator 

that as long as feasible technology permits the demand 

for new passenger automobiles to be generally met, the 

basic requirements of the Act would be satisfied, even 

though this might occasion fewer models and a more 

limited choice of engine types. The driving 

preferences of hot rodders are not to outweigh the 

goal of a clean environment.150 

Similarly, in a 2007 decision under CAA §112, NRDC v. EPA, 

489 F.3d 1364, 1376 (D.C. Cir. 2007) the D.C. Circuit upheld the 

EPA’s decision to apply the same hazardous air pollutant 

requirements to different types of plywood and composite wood 

products facilities – even though one of those types of 

facilities faced greater difficulties meeting the requirements 

than the other types of facilities – in part on the grounds that 

the facilities “compet[ed] in the same markets.”151

3. Section 111 rulemaking precedent 

 Through long-standing rulemaking precedent, the EPA has 

taken the position that section 111 authorizes a standard of 

performance for a source category that may not be feasible for 

all types of new sources in the category, as long as there are 

other types of sources in the category that can serve the same 

function and meet the standard. Specifically, in a 1976 

 

150 International Harvester Co. v. EPA, 478 F.2d at 640. 151 NRDC v. EPA, 489 F.3d at 1376.

Comment [A70]: This is helpful – is there any 

further elaboration that could be made on this point, 

particularly to connect this with the electricity 

market? 

Comment [A71]: Added for clarification 
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rulemaking under section 111 covering primary copper, zinc, and 

lead smelters, the EPA established, as the standard of 

performance, a single standard for SO2 emissions for new 

construction or modifications of reverberatory, flash, and 

electric smelting furnaces in primary copper smelters that 

process materials with low levels of volatile impurities. The 

EPA acknowledged that although for flash and electric smelting 

furnaces, the cost of the controls was “reasonable,” for 

reverberatory smelting furnaces, the cost of the standard was 

“unreasonable in most cases.” Even so, the EPA determined that 

this standard would not adversely affect new construction or 

modification of primary copper smelters processing materials 

containing low levels of volatile impurities because new 

construction could use flash and electric smelting furnaces, and 

existing sources could expand without increasing emissions.152

The EPA explained: 

[T]he Agency believes that section 111 authorizes 

the promulgation of one standard applicable to all 

processes used by a class of sources, in order that 

the standard may reflect the maximum feasible control 

for that class. When the application of a standard to 

a given process would effectively ban the process, 

however, a separate standard must be prescribed for it 

unless some other process(es) is available to perform 

the function at reasonable cost.... 

 

152 Standards of Performance for New Stationary Sources, Primary 

Copper, Zinc, and Lead Smelters, 41 FR ____, 2333 (Jan. 15, 

1976). 
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The Administrator has determined that the flash 

copper smelting process is available and will perform 

the function of the reverberatory copper smelting 

process at reasonable cost....153

VII. Rationale for Emission Standards for New Fossil Fuel- fired 

Boilers and IGCCs 

A. Overview 

In this section we explain our rationale for concluding 

that partial implementation of CCS is the best system of 

emission reduction adequately demonstrated (BSER) for new fossil 

fuel-fired boiler and IGCC EGUs. 

As noted, CAA §111 and subsequent court decisions establish 

a set of factors for the EPA to consider in a BSER 

determination, including criteria listed in CAA §111 or 

identified in the court decisions and the underlying purposes of 

§111. Key factors include: emission reductions, technical 

feasibility, costs, and encouragement of technology. Other 

factors, such as energy impacts, may also be important. As also 

noted, the EPA has discretion in balancing those factors, and 

may balance them differently in promulgating standards for 

different source categories. 

The EPA considered three different control technology 

 

153 41 FR at 2333 (emphasis added). 

Comment [A72]: Should this reference standards 

of performance instead of BSER? Or, both? 
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configurations as potentially representing the BSER for new 

fossil fuel-fired boilers and IGCC units. Power company 

announcements indicate that the few new coal-fired projects that 

may occur will likely consider one or more of these three 

configurations. The three alternatives the EPA considered in the 

BSER analysis are: (1) highly efficient new generation 

technology that does not include any level of CCS, (2) new 

generation technology with “full capture” CCS (that is, CCS 

capture of at least 90 percent CO2 emissions) and (3) new 

generation technology with “partial capture” CCS (that is, CCS 

capture of a lower level of CO2 emissions). 

We discuss each of these alternatives below, and explain 

why we propose that partial capture CCS qualifies as the BSER. 

We first discuss the technical systems that we considered for 

the BSER, our evaluations of them, and our reasons for 

determining that only partial CCS meets the criteria to qualify 

as the BSER. We include in this discussion our rationale for 

selecting 1,100 lb CO2/MWh as the emission limitation for these 

sources and why we seek comment on a range from 1,000 to 1,200 

lb CO2/MWh. We next discuss our rationale for allowing a 60-

operating-month averaging period as an alternative compliance 

method, with the requirement that sources choosing that method 

Comment [A73]: Is it “few” or “none”. Suggest 

adding a sentence before power company sentence 

stating that EIA projects none,. 
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meet a limit of between 1,000 lb CO2/MWh and 1,050 lb CO2/MWh.154

We then explain our rationale for the requirements for geologic 

sequestration. 

B. Identification of the best system of emission reduction

1. Highly efficient new generation without CCS technology 

Some commenters on the April 2012 proposal suggested that 

the emission limitation for new coal-fired EGUs should be based 

on the performance of highly efficient generation technology 

that does not include CCS, such as (i) a supercritical155

pulverized coal (SCPC) or circulating fluidized bed (CFB) 

boiler, or (ii) a modern, well-performing IGCC unit. 

These options are clearly technically feasible. However, we 

do not consider them to qualify as the BSER for the following 

reasons: 

a. Lack of significant CO2 reductions 

Because of the large amount of CO2 emissions from solid-fuel 

fired power plants, it is important, in promulgating a standard 

 

154 This is on a gross output basis. All other emissions in this 

section are listed as gross output unless specifically noted 

otherwise. 

155 Subcritical coal-fired boilers are designed and operated with 

a steam cycle below the critical point of water. Supercritical 

coal-fired boilers are designed and operated with a steam cycle 

above the critical point of water. 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. 

Comment [A74]: The NOPR uses “clearly” a fair 

amount, and the use does not add persuasiveness. 

Consider omitting. 
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of performance for these sources, to give effect to the purpose 

of CAA §111 of providing “as much [emission reduction] as 

practicable.”156 Accordingly, we reviewed the emission rates of 

efficient PC and CFB units. According to the DOE/NETL estimates, 

a new subcritical pulverized coal (PC) unit firing bituminous 

coal would emit 1,783 lb CO2/MWh,157 a new SCPC unit using 

bituminous coal would emit 1,675 lb CO2/MWh, and a new IGCC 

unit158 would emit 1,434 lb CO2/MWh.159 

New power sector projects using coal as a primary fuel that 

have been proposed or are currently under construction are 

generally SCPC or IGCC projects. For example, since 2007, almost 

all coal-fueled EGUs that have broken ground have been high 

performing versions of SCPC or IGCC projects.160 Among those 

plants are: (1) AEP’s John W. Turk, Jr. Power Plant, a 600 MW 

 

156 Sierra Club, F.2d at 327 & n. 83 (quoting 44 FR at 33,581/3 – 

33,582/1).

157 Exhibit ES-2 from “Cost and Performance Baseline for Fossil 

Energy Plants Volume 1: Bituminous Coal and Natural Gas to 

Electricity”, Revision 2, Report DOE/NETL-2010/1397 (November 

2010). 

158 “Case 1” from Exhibit ES-2 from “Cost and Performance 

Baseline for Fossil Energy Plants Volume 1: Bituminous Coal and 

Natural Gas to Electricity”, Revision 2, Report DOE/NETL2010/1397 (November 2010).

159 The comparable emissions on a net basis are: subcritical PC – 

1,888 lb CO2/MWh; supercritical PC – 1,768 lb CO2/MWh; and IGCC – 

1,723 lb CO2/MWh. 160 The only exception that we are aware of is the Virginia City 

subcritical CFB unit 

Comment [A75]: What are the CO2 emissions of 

the subcritical CFB? The FN contains only minimal 

discussion; should elaborate. 
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ultra-supercritical161 PC (USCPC) facility located in the 

southwest corner of Arkansas; (2) Duke Power’s Edwardsport 

plant, a 618 MW coal IGCC unit located in Knox County, Indiana; 

and (3) Southern Company’s Kemper County Energy Facility, a 582 

MW lignite IGCC unit located in Kemper County, Mississippi. 

These facilities all use advanced generation technology: Turk, 

as noted, is an ultra-supercritical boiler; Edwardsport is an 

IGCC unit that is “CCS ready;” and Kemper is an IGCC unit that 

will implement partial CCS. 

Under these circumstances, in this rule, identifying a new 

supercritical unit as the BSER and requiring the associated 

emission limitation of approximately 1,675 lb CO2/MWh, would 

provide little meaningful CO2 emission reductions for this source 

category. As noted, for the most part, new sources are already 

designed to achieve at least that emission limitation. 

Identifying IGCC as the BSER and requiring the associated 

emission limitation of approximately 1,434 lb CO2/MWh, would 

provide some CO2 emission reductions from the segment of the 

industry that would otherwise construct new PC units, but not 

from the segment of the industry that would already construct 

 

161 Ultra-supercritical (USC) and advanced ultra-supercritical 

(A-USC) are terms often used to designate a coal-fired power 

plant design with steam conditions well above the critical 

point.
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new IGCC units. 

As a result, emission reductions in the amount that would 

result from an emission standard based on SCPC/USCPC or even 

IGCC as the BSER would not be consistent with the purpose of CAA 

§111 to achieve “as much [emission reduction] as practicable.”162

As we discuss below, identifying CCS-partial capture as the BSER 

would provide for significantly greater emissions reductions. 

b. Lack of incentive for technological innovation 

Identifying highly efficient generation technology as the 

BSER would not achieve another purpose of CAA §111, to encourage 

the development and implementation of control technology. At 

present, CCS technologies are the most promising options to 

achieve significant reductions in CO2 emissions from solid 

fossil-fuel fired EGUs. A standard based on the performance of 

highly efficient coal-fired generation does not advance the 

development and implementation of control technologies that 

reduce CO2 emissions. 

On the contrary, such a standard could impede the 

advancement of CCS technology by creating regulatory 

disincentives for such technology. In 2011, American Electric 

Power (AEP) deferred construction of a large-scale CCS retrofit 

 

162 Sierra Club, F.2d at 327 & n. 83 (quoting 44 FR at 33,581/3 – 

33,582/1).

Comment [A76]: Promising or effective? 
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demonstration project on one of their coal-fired power plants 

because the state’s utility regulators would not approve cost 

recovery for CCS investments without a regulatory requirement to 

reduce CO2 emissions. AEP’s chairman was explicit on this point, 

stating in a July 17, 2011 press release announcing the 

deferral: 

We are placing the project on hold until economic 

and policy conditions create a viable path forward ... 

We are clearly in a classic ‘which comes first?’ 

situation. The commercialization of this technology is 

vital if owners of coal-fueled generation are to 

comply with potential future climate regulations 

without prematurely retiring efficient, cost-effective 

generating capacity. But as a regulated utility, it is 

impossible to gain regulatory approval to recover our 

share of the costs for validating and deploying the 

technology without federal requirements to reduce 

greenhouse gas emissions already in place. The 

uncertainty also makes it difficult to attract 

partners to help fund the industry’s share.163

As we discuss below, regulatory requirements for CO2

reductions with some level of CCS as the BSER will promote 

further development of the technology. 

2. Carbon capture and storage 

We have also considered whether the emission limitation for 

new coal-fired EGUs should be based on the performance of CCS, 

including either “full capture” CCS that treats the entire flue 

gas or syngas stream to achieve on the order of 90 percent 

 

163 http://www.aep.com/newsroom/newsreleases/?id=1704
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reduction in CO2 emissions, or “partial capture” CCS that 

achieves some level less than 90 percent of capture. 

We propose that implementation of partial capture CCS 

technology is the BSER for new fossil fuel-fired boilers and 

IGCC units because it fulfills the criteria established under 

CAA §111. In the sections that follow, we explain the technical 

configurations that facilitate full and partial capture, 

describe the operational flexibilities that partial capture 

offers, and then identify and justify the emission rate that we 

propose based on partial capture. After that, we discuss the 

criteria for BSER, and describe why partial capture meets those 

criteria and why full capture does not. Among other things, 

partial capture provides meaningful emission reductions, it has 

been adequately demonstrated to be technically feasible, it can 

be implemented at a not unreasonable cost, and it promotes 

deployment and further development of the technology. 

3. Technical configurations for CCS 

The DOE’s National Energy Technology Laboratory (NETL) 

performed a study to establish the cost and performance for a 

range of CO2 capture levels for new SCPC and IGCC power plants.164

 

164 “Cost and Performance of PC and IGCC Plants for a Range of 

Carbon Dioxide Capture”, DOE/NETL-2011/1498, May 27, 2011. 
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The study identified technical configurations that were tailored 

to achieve a specific level of carbon capture. 

a. SCPC 

For the new SCPC case, the study assumed a new SCPC boiler 

with a combination of low-NOx burners (LNB) with overfire air 

(OFA) and a selective catalytic reduction (SCR) system for NOx 

control. The plant was assumed to have a fabric filter and a wet 

limestone flue gas desulfurization (FGD) scrubber for 

particulate matter and sulfur dioxide (SO2) control, 

respectively. The plant was also assumed to have a sodium 

hydroxide (NaOH) polishing scrubber to ensure that the flue gas 

entering the CO2 capture system has a SO2 concentration of 10 

ppmv or less. The SCPC plant was equipped with Fluor’s Econamine 

FG PlusSM process for post-combustion CO2 capture via temperature 

swing absorption with a monoethanolamine (MEA) solution as the 

chemical solvent. 

The study’s authors identified two options for achieving 

partial capture (i.e., less than 90 percent CO2 capture) in the 

SCPC unit. The first option was to process the entire flue gas 

stream through the MEA capture system at reduced solvent 

circulation rates. The second option was to maintain the same 

high solvent circulation rate and steam stripping requirement as 

would be used for full capture but only treat a portion of the 
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total flue gas stream. The authors determined that the second 

approach – the “slip stream” approach - was the most economical. 

The authors further noted that the cost of CO2 capture with an 

amine scrubbing process is dependent on the volume of gas being 

treated, and a reduction in flue gas flow rate will: (1) 

decrease the quantity of energy consumed by flue gas blowers, 

(2) reduce the size of the CO2 absorption columns, and (3) trim 

the cooling water requirement of the direct contact cooling 

system. The slip stream approach leads to lower capital and 

operating costs. All of the partial capture cases in the NETL 

study assumed this approach. 

a. IGCC 

For a new IGCC unit, the product syngas would contain 

primarily hydrogen (H2), carbon monoxide (CO) and some lesser 

amount of CO2.165 The amount of CO2 can be increased by “shifting” 

the composition via the catalytic water-gas shift (WGS) 

reaction. This process involves the catalytic reaction of steam 

(“water”) with CO (“gas”) to form H2 and CO2. An emission 

standard that requires partial capture of CO2 from the syngas 

could be met by adjusting the level of CO2 in the syngas stream 

 

165 The amount of CO2 in un-shifted syngas depends upon the 

specific gasifier technology used, the operating conditions, and 

the fuel used; but is typically less than 20 volume percent 

(http://www.netl.doe.gov/technologies/coalpower/gasification/gas

ifipedia/4-gasifiers/4-3_syngas-table2.html). 
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by controlling the level of syngas “shift” prior to treatment in 

the pre-combustion acid gas treatment system. 

For a new IGCC EGU, the study’s authors assumed the use of 

the GE gasifier coupled with a variety of potential 

configurations (i.e., no WGS reactor, single-stage WGS, twostage WGS, varying WGS bypass ratios, and CO2 scrubber removal 

efficiency). The study evaluated a number of IGCC plant 

configurations. The first was an IGCC that used the SelexolTM 

process for acid gas control (i.e., hydrogen sulfide (H2S) and 

CO2) but no WGS reactor. This unit was capable of CO2 capture 

ranging from zero up to 25 percent. The no-CO2 capture case 

employed a one-stage SelexolTM unit for H2S control and the 25 

percent CO2 capture case utilized a two-stage SelexolTM unit to 

maximize CO2 capture from the unshifted syngas (i.e., >90 percent 

of the CO2 from the unshifted syngas was captured in the second 

stage SelexolTM scrubber). 

To achieve moderate levels of partial CO2 capture – 

approximately 25 to 75 percent - the IGCC was configured with a 

single-stage WGS reactor with bypass and a two-stage SelexolTM 

unit. Varying the extent of the WGS reaction by controlling the 

amount of syngas that was processed through the WGS reactor (by 

controlling the amount that bypassed the WGS reactor) 

manipulated the level of CO2 capture. As more syngas is processed 
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through the WGS reactor, the steam demand increases. The 

SelexolTM removal efficiency was manipulated by varying the 

solvent circulation rate. Thus, a facility using this 

configuration could select or “dial in” a level of control of 

between 25 – 75 percent. 

To achieve higher CO2 capture levels – levels greater than 

75 percent - the IGCC was configured with a two-stage WGS with 

bypass and the two-stage acid gas (SelexolTM) scrubbing system. 

The facility could “dial in” a level of control of between 25 to 

greater than 90 percent by controlling the WGS bypass and the 

SelexolTM scrubber recirculation rates. 

The water-gas shift involves the following catalytic 

reaction of syngas carbon monoxide and steam: 

CO + H2O 

∆

՜ CO2 + H2

Since the syngas initially contains primarily CO and H2, 

this shift reaction diminishes the concentration of CO and 

enriches the concentration of H2 in the pre-combustion syngas 

stream. An unshifted or partially shifted syngas can be 

combusted using a typical combustion turbine. However, as the 

level of H2 in the syngas increases, the more the syngas must be 

diluted with N2 or air. Very high levels of H2 in the syngas 

stream require use of a specialty hydrogen turbine. 

4. Operational and design flexibility 
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To this point, most of the studies involving research, 

development and demonstration of carbon capture technology, 

along with most of the studies that have modeled the costs and 

implementation of such technology have assumed capture 

requirements of 90 percent for fossil fuel-fired power plants 

(“full capture”). However, the EPA believes that partial capture 

provides significant benefits because an emission limit based on 

partial capture offers operators considerable operational 

flexibility. With such emission limits, project developers would 

have the option of designing and installing CO2 capture 

technology at a size sufficient to treat the entire flue gas 

stream, with the capability to meet CO2 emission limits that are 

much lower than required. The operator of the plant could then 

choose to achieve those deeper capture rates during non-peak 

electricity demand periods and to achieve lesser capture rates 

(and thus generate more electricity) during peak electricity 

demand periods. This type of operational flexibility provides 

owners and operators the opportunity to optimize the operation 

and minimize the cost of CCS in new fossil fuel-fired projects. 

In addition, an emission standard that can be met with 

partial capture offers the opportunity for design flexibility. A 

project developer of a new conventional coal-fired plant (i.e., 

a new supercritical PC or CFB) could install post-combustion CO2
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scrubbers that have been designed and sized to treat only a 

portion of the flue gas stream. 

For a new IGCC unit, as noted, an emission standard that 

requires partial capture of CO2 offers operational flexibility 

because the standard could be met by adjusting the level of CO2

in the syngas stream by controlling the level of syngas “shift” 

prior to treatment in the pre-combustion acid gas treatment 

system. 

C. Determination of the level of the standard

Once the EPA has determined that a technology has been 

adequately demonstrated based on cost and other factors, 

including the impact a standard will have on further technology 

development and therefore represents BSER, the EPA must 

establish an emission standard. In this case, for new fossil 

fuel-fired boiler and IGCC EGUs, the EPA is finding that the 

level of partial capture of CO2 that qualifies as the BSER 

supports a standard of 1,100 lb CO2/MWh on a gross basis. The 

level of the standard is based on the emission reductions that 

can be achieved by an IGCC with a single-stage WGS reactor and a 

two-stage acid gas removal system. According to the DOE/NETL 

partial capture study, an IGCC with this configuration would be 

expected to achieve a CO2 emission reduction of 25 to 75 percent, 

which corresponds to emissions of approximately 1,060 and 380 lb 
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CO2/MWh-gross, respectively. The EPA is proposing a standard of 

performance of 1,100 lb CO2/MWh-gross, which is the high end of 

this range, for several reasons. 

First, both a new IGCC and a conventional coal-fired boiler 

(PC or CFB), can achieve this emission standard at a reasonable 

cost and the standard is based on technology that has been 

adequately demonstrated. 

The partial capture requirement and standard of performance 

will allow new IGCC project developers to minimize the need for 

multi-stage water-gas shift reactors (and the associated steam 

requirement) and will allow for the continued use of 

conventional syngas combustion turbines (rather than requiring 

the use of advanced hydrogen turbines). Second, this partial 

capture configuration will provide operators with operational 

flexibility. Third, this level of the standard best promotes 

further enhancement of the performance of existing technology 

and promotes continued development of new, better performing 

technology. It will provide developers with the opportunity to 

investigate new emerging and potentially lower-cost 

technologies. For instance, developers could build plants with 

the capacity to achieve deeper CO2 reductions and choose to 

employ those greater capture rates during non-peak periods, and 

Comment [A77]: Could EPA further explain 

why it believes the level of standard that can be met 

by existing technologies would spur development of 

new, better performing technology? 
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then employ lower capture rates (and thus generate more 

electricity) during peak periods. 

While the EPA is proposing an emission rate of 1,100 lb 

CO2/MWh, we are also soliciting comment on whether the emission 

limit may be more appropriately set at a different level within 

the range of 1,000 to 1,200 lb CO2/MWh. An emission rate of 1,200 

lb CO2/MWh could potentially be met by an IGCC unit that does not 

include a WGS reactor – thus further reducing the capital and 

operating costs. An emission limit of 1,000 lb CO2/MWh would 

provide greater emission reductions and would also advance CCS 

technology but would offer less operational flexibility. 

The next several sections review the factors for 

determining BSER and explain why partial capture at the level we 

are proposing meets those requirements, as well as why full 

capture does not meet some of them. 

D. Extent of reductions in CO2 emissions

The proposed standard of 1,100 lb CO2/MWh will provide 

meaningful reductions in emissions. As mentioned earlier, the 

DOE/NETL has estimated that a new supercritical PC using 

bituminous coal would emit 1,675 lb CO2/MWh. The DOE/NETL has 

also estimated that a new IGCC unit would emit 1,434 lb CO2/MWh. 

The emissions would be higher for units utilizing subbituminous 

coal or lignite and will vary when utilizing other fossil fuels 
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such as petroleum coke or mixtures of fuels. We estimate that 

this standard will result in reduction in emissions of at least 

40 percent when compared to the expected emissions of a new 

supercritical PC boiler. 

E. Technical feasibility

 The EPA proposes to find that partial CCS is feasible 

because each step in the process has been demonstrated to be 

feasible through an extensive literature record, fossil fuelfired industrial plants currently in commercial operation and 

pilot-scale fossil fuel-fired EGUs currently in operation, and 

the progress towards completion of construction of fossil fuelfired EGUs implementing CCS at commercial scale. This literature 

record and experience demonstrate that partial CCS is achievable 

for all types of new boiler and IGCC configurations. Although 

much of this information also serves to demonstrate the 

technical feasibility of full capture, we note that the several 

of the CCS projects that are the furthest along are partial 

capture projects, which further supports our view that partial 

capture is BSER. 

1. Literature 

The current status of CCS technology was described and 

analyzed by the 2010 Interagency Task Force on CCS, established 

by President Obama on February 3, 2010, co-chaired by the DOE 
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and the EPA, and composed of 14 executive departments and 

federal agencies. The Task Force was charged with proposing a 

plan to overcome the barriers to the widespread, cost-effective 

deployment of CCS within 10 years, with a goal of bringing five 

to ten commercial demonstration projects online by 2016. The 

Task Force found that, although early CCS projects face economic 

challenges related to climate policy uncertainty, first-of-akind technology risks, and the current cost of CCS relative to 

other technologies, there are no insurmountable technological, 

legal, institutional, regulatory or other barriers that prevent 

CCS from playing a role in reducing GHG emissions.166

The Pacific Northwest National Laboratory (PNNL) recently 

prepared a study that evaluated the development status of 

various CCS technologies for the DOE.167 The study addressed the 

availability of capture processes, transportation options (CO2

pipelines), injection technologies, and measurement, 

verification and monitoring technologies. The study concluded 

that, in general, CCS is technically viable today and that key 

component technologies of complete CCS systems have been 

deployed at scales large enough to meaningfully inform 

discussions about CCS deployment on large commercial fossil-

 

166 Report of the Interagency Task Force on Carbon Capture and 

Storage (August 2010), page 7. 

Comment [A78]: Does the task force findings 

say anything about leakage from geological storage 

and ways to manage for leakage? Suggest that this 

information could be cited somewhere in the 

rulemaking, if it exisits. 
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fired power plants. 

In addition, DOE/NETL has prepared additional reports – in 

particular their “Cost and Performance Baseline” reports168

including one on partial capture169 -- that further support the 

technical feasibility of partial capture. 

2. Capture, transportation and storage technologies 

Each of the core components of CCS -- CO2 capture, 

compression, transportation and storage have already been 

implemented on a commercial scale. 

a. CO2 capture technology 

Capture of CO2 from industrial gas streams has occurred 

since the 1930s using a variety of approaches to separate CO2

from other gases. These processes have been used in the natural 

gas industry and to produce food and chemical-grade CO2. Although 

current capture technologies are feasible, the costs of CO2

capture and compression represent the largest barriers to 

widespread commercialization of CCS. Currently available CO2

capture and compression processes are estimated to represent 70 

 

168 The “Cost and Performance Baseline” reports are a series of 

reports by DOE/NETL that establish estimates for the cost and 

performance of combustion- and gasification-based power plants - 

all with and without CO2 capture and storage. Available at 

www.netl.doe.gov/energy-analyses/baseline_studies.html 

169 “Cost and Performance of PC and IGCC Plants for a Range of 

Carbon Dioxide Capture”, DOE/NETL-2011/1498, May 27, 2011. 

Comment [A79]: It would be helpful to 

summarize the reports to substantiate the statement 

that these reports support the technical feasibility 

determination by EPA. 
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to 90 percent of the overall CCS costs.170

In general, CO2 capture technologies applicable to coalfired power generation can be categorized into three 

approaches:171

 Pre-combustion systems that are designed to separate CO2 and 

H2 in the high-pressure syngas produced at IGCC power 

plants. 

 Post-combustion systems that are designed to separate CO2

from the flue gas produced by fossil-fuel combustion in 

air. 

 Oxy-combustion that uses high-purity O2, rather than air, to 

combust coal and thereby produce a highly concentrated CO2

stream. 

Each of these three carbon capture approaches (precombustion, post-combustion, and oxy-combustion) is 

technologically feasible. However, each results in increased 

capital and operating costs and decreased electricity output 

(that is, an energy penalty), with a resulting increase in the 

cost of electricity. The energy penalty occurs because the CO2

capture process uses some of the energy (e.g., electricity, 

 

170 Report of the Interagency Task Force on Carbon Capture and 

Storage (August 2010). 

171 IPCC, 2005; DOE, 2007.
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steam, heat) produced from the plant. 

b. CO2 transportation 

Carbon dioxide has been transported via pipelines in the 

U.S. for nearly 40 years. Approximately 50 million metric tons 

of CO2 are transported each year through 3,600 miles of 

pipelines. Moreover, a review of the 500 largest CO2 point 

sources in the U.S. shows that 95 percent are within 50 miles of 

a possible geologic sequestration site,172 which would lower 

transportation costs. For these reasons, the transportation 

component of CCS is not expected to be a significant impediment 

to the commercial availability of CCS in the future. 

c. CO2 storage 

(i) Current availability of geologic sequestration 

Geologic storage potential for CO2 is widespread and 

available throughout the U.S. and Canada. Estimates based on DOE 

studies indicate that areas of the U.S. with appropriate geology 

have a storage potential of 2,300 billion to more than 20,000 

billion metric tons of CO2 in deep saline formations, oil and gas 

 

172 JJ Dooley, CL Davidson, RT Dahowski, MA Wise, N Gupta, SH 

Kim, EL Malone (2006), Carbon Dioxide Capture and Geologic 

Storage: A Key Component of a Global Energy Technology Strategy 

to Address Climate Change. Joint Global Change Research 

Institute, Battelle Pacific Northwest Division. PNWD-3602. 

College Park, MD.

Comment [A80]: Can EPA address the costs 

associated with any new pipelines that could be used 

for transportation? Or the costs to get from a facility 

to a GS site? 

Comment [A81]: Can EPA provide a more direct 

explanation of how the permanence of storage has 

been demonstrated? The explanation that follows 

talks about how storage locations and opportunities 

are available for geologic sequestration and EOR, 

but does not discuss evidence that CO2 can actually 

be technically stored for long periods of time. I 

believe that evidence exists, but would be good to 

explain directly. 
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reservoirs and un-mineable coal seams.173 Other types of geologic 

formations such as organic rich shale and basalt may also have 

the ability to store CO2; and the DOE is currently evaluating 

their potential storage capacity. 

Potential geologic sequestration sites must undergo 

appropriate site characterization to ensure that the site can 

safely and securely store CO2. Estimates of CO2 storage resources 

by state/province are compiled by the DOE’s National Carbon 

Sequestration Database and Geographic Information System 

(NATCARB). 

Further evidence of the widespread availability CO2 storage 

reserves in the U.S. comes from the Department of Interior’s 

U.S. Geological Survey (USGS) which has recently completed a 

comprehensive evaluation of the technically accessible storage 

resource for carbon storage for 36 sedimentary basins in the 

onshore areas and State waters of the United States.174 The USGS 

assessment estimates a mean of 3,000 billion metric tons of 

subsurface CO2 storage potential across the United States. For 

comparison, this amount is 500 times the 2011 annual U.S. 

 

173 The United States 2012 Carbon Utilization and Storage Atlas, 

Fourth Edition, U.S Department of Energy, Office of Fossil 

Energy, National Energy Technology Laboratory (NETL).

174 U.S. Geological Survey Geologic Carbon Dioxide Storage 

Resources Assessment Team, 2013, National assessment of geologic 

carbon dioxide storage resources – Results: U.S. Geological 

Survey Circular 1386, 41 p., http://pubs.usgs.gov/fs/2013/1386/. 
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energy-related CO2 emissions of 5.5 Gigatons (Gt).175

Nearly every state in the U.S. has or is in close proximity 

to formations with carbon storage potential including vast areas 

offshore. At the end of 2012 three large-scale geologic 

sequestration projects were underway in the U.S., with a goal of 

injecting more than 1 million tonnes of CO2. The U.S. experience 

with large-scale CO2 injection, such as at enhanced oil and gas 

recovery projects, combined with ongoing research, development, 

and demonstration programs in the U.S. and throughout the world, 

provide confidence that the storage - along with capture, 

compression and transport - of large amounts of CO2 can be 

achieved. 

(ii) Current availability of enhanced oil and gas recovery 

Geologic storage options also include use of CO2 in enhanced 

oil recovery. Enhanced recovery (ER), which includes both 

enhanced oil and gas recovery (EOR and EGR), refers to the 

injection of fluids into a reservoir to increase oil and/or gas 

production efficiency. ER is typically conducted at a reservoir 

after production yields have decreased from primary production. 

Fluids commonly used for ER include brine, fresh water, steam, 

 

175 U.S. Geological Survey Geologic Carbon Dioxide Storage 

Resources Assessment Team, 2013, National assessment of geologic 

carbon dioxide storage resources – Summary: U.S. Geological 

Survey Factsheet 2013-3020, 

6p.http://pubs.usgs.gov/fs/2013/3020/.

Comment [A82]: And to put this in context, 

consider adding a clause at the end that notes what 

percent 1 million tonnes of CO2 is out of total 

availability estimates in the US 

Comment [A83]: This seems less focused on 

availability of CO2 storage. Consider omitting. 
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nitrogen, alkali solutions, surfactant solutions, polymer 

solutions, and carbon dioxide. EOR using carbon dioxide, 

sometimes referred to as ’CO2 flooding’ or CO2-EOR, involves 

injecting carbon dioxide into an oil reservoir to help mobilize 

the remaining oil and make it available for recovery. The crude 

oil and CO2 mixture is produced, and sent to a separator where 

the crude oil is separated from the gaseous hydrocarbons and CO2. 

The gaseous CO2-rich stream then is typically dehydrated, 

purified to remove hydrocarbons, recompressed, and re-injected 

into the oil or natural gas reservoir to further enhance 

recovery. 

CO2-EOR has been successfully used at many production fields 

throughout the U.S. to increase oil recovery. The oil and 

natural gas industry in the United States has over 40 years of 

experience of injection and monitoring of CO2 in the deep 

subsurface for the purposes of enhancing oil and natural gas 

production. This experience provides a strong foundation for the 

injection and monitoring technologies that will be needed for 

successful deployment of CCS. Although deep saline formations 

provide the most CO2 storage opportunity (2,102 to 20,043 billion 

metric tons), oil and gas reservoirs are currently estimated to 

Comment [A84]: Does the monitoring ensure 

that CO2 is stored long-term, and therefore 

“successful”. Are there references that could be 

added here that provide background on the 

monitoring of CO2-EOR? 
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have 226 billion metric tons of CO2 storage resource.176 

The EPA anticipates that many early geologic sequestration 

projects may be sited in active or depleted oil and gas 

reservoirs because these formations have been previously well 

characterized for hydrocarbon recovery, likely already have 

suitable infrastructure (e.g., wells, pipelines, etc.), have an 

associated economic benefit of oil production, and may be 

suitable for long term containment of CO2. 

CO2-EOR is the fastest-growing EOR technique in the U.S., 

providing approximately 281,000 barrels of oil per day in the 

U.S. which equals about 6 percent of U.S. crude oil production. 

The vast majority of CO2-EOR is conducted in oil reservoirs in 

the U.S. Permian Basin, which extends through southwest Texas 

and southeast New Mexico. Other U.S. states where CO2-EOR is 

utilized are Alabama, Colorado, Illinois, Kansas, Louisiana, 

Michigan, Mississippi, New Mexico, Oklahoma, Utah, and Wyoming. 

A well-established and expanding network of pipeline 

infrastructure supports CO2-EOR in these areas. The CO2 supply 

for EOR operations currently is largely obtained from natural 

underground formations or domes that contain CO2. While natural 

 

176 U.S. Department of Energy National Energy Technology 

Laboratory (2012). United States Carbon Utilization and Storage 

Atlas, Fourth Edition. 

Comment [A85]: Why is this statement qualified 

(“may be”)? 
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sources of CO2 comprise the majority of CO2 supplied for EOR 

operations, recent developments targeting anthropogenic sources 

of CO2 (e.g., ethanol plants, gas processing, refineries, power 

plants) have expanded or led to planned expansions in existing 

infrastructure related to CO2-EOR. Several hundred miles of 

dedicated CO2 pipeline is under construction, planned, or 

proposed that would allow continued growth in CO2 supply for EOR. 

Potential sources of CO2 for EOR continue to increase as new 

projects are being planned or implemented. Based on an 

evaluation of publicly available sources, the EPA notes there 

are currently twenty-two industrial source CCS projects in 

twelve states that are either operational, under-construction, 

or actively being pursued which are or will supply captured CO2

for the purposes of EOR. This further demonstrates that CCS 

projects associated with large point sources are occurring due 

to a demand for CO2 by EOR operations. Nationally, according to 

the EPA’s Greenhouse Gas Reporting Program, over 64 million 

metric tons of CO2 were received for injection to enhanced oil 

recovery operations in 2011. A recent study by DOE found that 

the market for captured CO2 emissions from power plants created 

by economically feasible CO2-EOR projects would be sufficient to 

permanently store the CO2 emissions from 93 large (1,000 MW) 

Comment [A86]: Is there a reference that can be 

added that summarizes these projects? 
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coal-fired power plants operated for 30 years.177 Based on all of 

these factors, the EPA anticipates opportunities to utilize CO2-

EOR operations for geologic storage will continue to increase. 

Based on a recent resource assessment by the DOE, the 

application of next generation CO2-EOR technologies would 

significantly increase oil production areas, further expanding 

the geographic extent and accessibility of CO2-EOR operations in 

the U.S.178 Additionally, oil and gas fields now considered to be 

‘depleted’ may resume operation because of increased 

availability and decreased cost of anthropogenic CO2, and 

developments in EOR technology, thereby increasing the demand 

for and accessibility of CO2 utilization for EOR. 

 The use of CO2 for EOR can significantly lower the net cost 

of implementing CCS. The opportunity to sell the captured CO2 for 

EOR, rather than paying directly for its long-term storage, 

improves the overall economics of the new generating unit. 

According to the International Energy Agency (IEA), of the CCS 

projects under construction or at an advanced stage of planning, 

70 percent intend to use captured CO2 to improve recovery of oil 

in mature fields. 

 

177 “Improving Domestic Energy Security and Lowering CO2

Emissions with “Next Generation” CO2-Enhanced Oil Recovery (CO2-

EOR)”, DOE/NETL-2011/1504 (June 20, 2011). 

178 Ibid. 
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(iii) Alternatives to geologic sequestration 

In the development of this proposal, the EPA has identified 

some potential alternatives to geologic sequestration, including 

but not limited to CO2 stored in precipitated calcium carbonate 

and certain types of cement. The EPA solicits comment on whether 

these and other alternatives to geologic sequestration, 

permanently store CO2 and if they are technically available for 

EGUs to meet the performance standard. Consideration of how 

these alternatives could meet the performance standard involves 

understanding the ultimate fate of the captured CO2 and the 

degree to which the method permanently isolates the CO2 from the 

atmosphere, as well as existing methodologies to verify this 

permanent storage. The EPA proposes that alternatives to 

geologic sequestration could not be used until the EPA finalizes 

a mechanism for that alternative to demonstrate permanent 

storage of CO2. The EPA believes that the number of cases where 

an EGU would seek to comply with the rule through an alternative 

will be very small. However the EPA wishes to encourage 

development of alternatives to geologic sequestration that could 

help offset the cost of CO2 capture. 

3. Examples of CCS demonstration projects 

The following is a brief summary of some examples of 

currently operating or planned CO2 capture or storage systems, 

Comment [A87]: Considering that this standard 

is set forth for other alternatives, EPA should address 

how EPA’s proposal meets this test. 

Comment [A88]: Need to clarify that this is not a 

complete list (or is it?). 
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including, in some cases, components necessary for coal-based 

power plant CCS applications. 

AES’s coal-fired Warrior Run (Cumberland, MD) and Shady 

Point (Panama, OK) power plants are equipped with amine 

scrubbers developed by ABB/Lummus. They were designed to process 

a slip stream of each plant’s flue gas. At Warrior Run, 

approximately 110,000 metric tons of CO2 per year are captured, 

whereas at Shady Point 66,000 metric tons of CO2 per year are 

captured. The CO2 from both plants is subsequently used in the 

food processing industry.179 

At the Searles Valley Minerals soda ash plant in Trona, CA, 

approximately 270,000 metric tons of CO2 per year are captured 

from the flue gas of a coal-fired power plant via amine 

scrubbing and used for the carbonation of brine in the process 

of producing soda ash.180

A pre-combustion Rectisol® system is used for CO2 capture at 

the Dakota Gasification Company’s synthetic natural gas 

production plant located in North Dakota, which is designed to 

remove approximately 1.6 million metric tons of CO2 per year from 

the synthesis gas. The CO2 is purified, transported via a 200-

 

179 Dooley, J. J., et al. (2009). An Assessment of the Commercial 

Availability of Carbon Dioxide Capture and Storage Technologies 

as of June 2009. U.S. DOE, Pacific Northwest National 

Laboratory, under Contract DE-AC05-76RL01830.

180 IEA (2009a), World Energy Outlook 2009, OECD/IEA, Paris.
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mile pipeline for use in EOR operations in the Weyburn oilfield 

in Saskatchewan, Canada. 

In September 2009, American Electric Power Co. (AEP) began 

a pilot-scale CCS demonstration at its Mountaineer Plant in New 

Haven, WV. The Mountaineer Plant is a 1,300 MWe coal-fired unit 

that was retrofitted with Alstom’s patented chilled ammonia CO2

capture technology on a 20 MWe slip stream of the plant’s 

exhaust flue gas. In May 2011, Alstom Power announced the 

successful operation of the chilled-ammonia CCS validation 

project. The demonstration achieved capture rates from 75 

percent (design value) to as high as 90 percent, produced CO2 at 

purity of greater than 99 percent, with energy penalties within 

a few percent of predictions. The facility reported robust 

steady-state operation during all modes of power plant operation 

including load changes, and saw an availability of the CCS 

system of greater than 90 percent. 

AEP, with assistance from the DOE, had planned to expand 

the slip stream demonstration to a commercial scale, fully 

integrated demonstration at the Mountaineer facility. The 

commercial-scale system was designed to capture at least 90 

percent of the CO2 from 235 MW of the plant's 1,300 MW total 

capacity. Plans were for the project to be completed in four 

phases, with the system to begin commercial operation in 2015. 
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However, in July 2011, AEP announced that it would terminate its 

cooperative agreement with the DOE and place its plans to 

advance CO2 capture and storage technology to commercial scale on 

hold, citing the uncertain status of U.S. climate policy as a 

contributor to the decision. 

Oxy-combustion of coal is being demonstrated in a 10 MWe 

facility in Germany. The Vattenfall plant in eastern Germany 

(Schwarze Pumpe) has been operating since September 2008. It is 

designed to capture 70,000 metric tons of CO2 per year. A larger 

scale project is in advanced stages of planning in the U.S. 

In June 2011, Mitsubishi Heavy Industries, an equipment 

manufacturer, announced the successful launch of operations at a 

25 MW coal-fired carbon capture facility at Southern Company's 

Alabama Power Plant Barry. The demonstration captures 

approximately 165,000 metric tons of CO2 annually at a CO2

capture rate of over 90 percent. The captured CO2 is being 

permanently stored underground in a deep saline geologic 

formation. 

Southern Company has begun construction of Mississippi 

Power Kemper County Energy Facility. This is a 582 MW IGCC plant 

that will utilize local Mississippi lignite and include precombustion carbon capture to reduce CO2 emissions by 65 percent. 

The captured CO2 will be used for enhanced oil recovery (EOR) in 

Comment [A89]: Any 2013 update? 

Comment [A90]: Are there any further details 

that can be added? 
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the Heidelberg Oil Fields in Jasper County, MS. The project is 

now more than 75 percent complete with start-up and operation 

expected to begin in 2014. 

The Texas Clean Energy Project, a 400 MW IGCC facility 

located near Odessa, Texas will capture 90 percent of its CO2, 

which is approximately 3 million metric tons annually. The 

captured CO2 will be used for EOR in the West Texas Permian 

Basin. Additionally, the plant will produce urea and smaller 

quantities of commercial-grade sulfuric acid, argon, and inert 

slag, all of which will also be marketed. The developer expects 

financing to be fully arranged in 2013. 

There are other CCS projects – domestic and worldwide -- 

that are helping to further develop the CCS technology. They are 

noted in the DOE/NETL’s Carbon Capture, Utilization, and Storage 

(CCUS) Database.181 The database includes active, proposed, 

canceled, and terminated CCUS projects worldwide. 

F. Costs

As noted, according to the D.C. Circuit case law, control 

 

181 Available at 

http://www.netl.doe.gov/technologies/carbon_seq/global/database/

Information in the database regarding technologies being 

developed for capture, evaluation of sites for carbon dioxide 

(CO2) storage, estimation of project costs, and anticipated dates 

of completion is sourced from publically available information. 

The CCUS Database provides the public with information regarding 

efforts by various industries, public groups, and governments 

towards development and eventual deployment of CCUS technology. 
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costs are considered acceptable as long as they are reasonable, 

meaning that such costs can be accommodated by the industry.182

To determine reasonableness, the Court has looked to the amount 

of the control costs, whether they could be passed on to the 

consumer, and how much they would lead prices to increase. As we 

discuss below, where EOR opportunities are available, the sale 

of captured CO2 offers the opportunity to defray much of the 

costs. However, we recognize that there are places where 

opportunities to sell captured CO2 for utilization in EOR 

operations may not be presently available. Nevertheless, as 

discussed below, our analysis shows that this cost structure – 

with and without EOR - is consistent with the D.C. Circuit’s 

criteria for determining that costs are reasonable. 

The costs of coal-fired electricity generation – even when 

not incorporating CCS technology – are high when compared to the 

current costs of new NGCC generation. Even so, some utilities 

and other project developers have indicated a willingness and 

desire to proceed with new fossil fuel-fired boilers and IGCC 

units. They have indicated the need for energy and fuel 

diversity. They have also indicated a skepticism regarding longterm projections for low natural gas prices and high 

 

182 In addition, the EPA may consider costs through a national 

lens, as discussed below.

Comment [A91]: Earlier in the rule, EPA states 

that it will refer throughout the rule to the test as 

“unreasonable”. Consider using “not unreasonable” 

here to align with that discussion. 

See p. 161: in this rulemaking, we will 

use the “unreasonable” formulation, 

so that a control technology cannot 

be considered the “best system of 

emission reduction ... adequately 

demonstrated” if its costs are 

“unreasonable.”

Comment [A92]: And other generation, yes? 

Can nuclear or wind also be mentioned here? 
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availability. And there may be other reasons why developers 

choose to build new coal-fired plants. For these reasons, we 

believe that these developers have indicated a willingness to 

proceed with non-NGCC projects, even if they currently do not 

appear to be the most economic choice. 

1. Cost estimates for implementation of partial CCS 

The EPA has examined costs of new power generation options. 

These options are shown in Table 4. The table shows the costs of 

new NGCC technology at two different natural gas prices – at 

$5/MMBtu, which is reasonably consistent with current and 

projected prices – and at $10/MMBtu, which would be well above 

current and projected natural gas prices. We also show costs for 

SCPC and IGCC units with no CCS (i.e., units that would not meet 

the proposed emission standard) and those units with partial 

capture CCS installed such that their emission would meet the 

proposed 1,100 lb CO2/MWh standard. We have also included costs 

for those units when EOR opportunities are available. We have 

included a “low EOR” case assuming a low EOR price of $20 per 

ton of CO2 plus the cost for transportation, storage and 

monitoring (TSM) costs, and a “high EOR” of $40/ton plus the 

cost for TSM. We also show the projected costs for 

implementation of full capture CCS (i.e., 90 percent capture). 

Table 4. Levelized Cost of Electricity for Electric Generating 

Technologies, Excluding Transmission Costs 

Comment [A93]: Probably worth a footnote 

explaining that this does not include savings from 

direct subsidies like tax credits. 
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Technology 

Cost of 

Electricity 

($2011/MWh)183,184

NGCC @ $5.0/MMBtu 52 

NGCC @ $10.0/MMBtu 86 

 

SCPC w/o CCS185 92 

SCPC (1,100 lb/MWh; no EOR) 110 

SCPC (1,100 lb/MWh; low EOR) 96 

SCPC (1,100 lb/MWh; high EOR) 88 

SCPC (full, 90 percent CCS) 147 

 

IGCC w/o CCS 97 

IGCC (1,100 lb/MWh; no EOR) 109 

IGCC (1,100 lb/MWh; low EOR) 101 

 

183 Data for fossil fuel-fired generation comes from DOE/NETL: 

(1) Cost and Performance Baseline for Fossil Energy Plants 

Volume 1: Bituminous Coal and Natural Gas to Electricity, Rev 2, 

DOE/NELT-2010/1397 (Nov 2010); (2) Updated Costs (June 2011 

Basis) for Selected Bituminous Baseline Cases” DOE/NETL341/082312 (Aug 2012); (3) Cost and Performance of PC and IGCC 

Plants for a Range of Carbon Dioxide Capture, DOE/NETL-2011/1498 

(May 2011).; Data for non-fossil fuel-fired generation comes 

from EIA AEO 2013 LCOE estimates from 

http://www.eia.gov/forecasts/aeo/electricity_generation.cfm; EIA 

estimates provided in this table do not include transmission 

investment to maintain consistency with DOE/NETL estimates. 

184 LCOE point estimates are provided for coal-fired capacity 

types; all other LCOE estimates are presented as a range that 

reflects EIA’s view on the regional variation in local labor 

markets, cost and availability of fuel, and renewable resources. 

The capacity factor ranges for renewable non-dispatchable 

technologies are as follows: Wind – 30% to 39%, Wind Offshore – 

33% to 42%, Solar PV- 22% to 32%, and Solar Thermal – 11% to 

26%. Capacity factors for dispatchable are technologies are as 

follows: Coal – 85%, Nuclear – 90%, Biomass – 83%, Geothermal – 

92%, and Combustion Turbine – 30%. There is no capacity credit 

provided to dispatchable resources. 

185 SCPC LCOE includes a 3% increase to the weighted average cost 

of capital to reflect EIA’s climate uncertainty adder (CUA). 
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IGCC (1,100 lb/MWh; high EOR) 97 

IGCC (full, 90 percent CCS) 136 

 

Nuclear 103 - 114 

Biomass 97 - 130 

Geothermal 80 – 99 

Combustion Turbine 87 – 116 

Onshore Wind 70 – 97 

Offshore Wind 177 – 289 

Solar PV186 109 – 220 

Solar Thermal 184 – 412 

It is important to note here that both the EIA and the EPA 

apply a climate uncertainty adder (CUA) - represented by a three 

percent increase to the weighted average cost of capital - to 

certain coal-fired capacity types. The EIA developed the CUA to 

address the disconnect between power sector modeling absent GHG 

regulation and the widespread use of a cost of CO2 emissions in 

power sector resource planning. 

The CUA reflects the additional planning cost typically 

assigned by project developers and utilities to GHG-intensive 

projects in a context of climate uncertainty. The EPA believes 

the CUA is consistent with the industry’s planning and 

evaluation framework (demonstrable through IRPs and PUC orders) 

and is therefore necessary to adopt in evaluating the cost 

competitiveness of alternative generating technologies. 

 

186 Costs are expressed in terms of net AC power available to the 

grid for the installed capacity.

Comment [A94]: This may benefit an 

explanation of why this uncertainty will still exist 

after this new source rulemaking (new sources will 

someday be subject to different standards, whether 

it’s existing source standards after the 8-yr review or 

a potentially new legislative regime). 
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EPA believes the CUA is relevant in considering the range 

of costs that power companies are willing to pay for generation 

alternatives to natural gas. To the extent that a handful of 

project developers are still considering coal without CCS, EPA 

believes they must fall into one of two classes. Either they 

are not factoring in any form of a CUA. In this case, based 

both on the analysis EIA undertook in developing the CUA 

approach and EPA’s review of IRP’s, companies that do this 

appear to be outliers. In other words, it appears that most 

companies in fact would not assume the costs without the CUA 

represents the potential cost (with risk) they would assign to a 

coal without CCS project. If they are, however, factoring in 

risk associated with carbon, that suggests they are, in fact, 

willing to pay the higher cost for coal without CCS (even if 

they are not actually incurring those costs today). For these 

reasons, EPA believes that it is appropriate not to give large 

consideration to the cost of coal without CCS and without the 

CUA in the range of costs that utilities are willing to pay for 

alternatives to natural gas. 

The EPA is requesting comment on both the CUA’s magnitude 

and technology-specific application with the intent of ensuring 

that the EPA’s supporting analysis best reflects the current 

standards and practices of the power sector’s long-term planning 
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process. 

2. Comparison with the costs of other new power generation 

options 

While new coal-fired generation that includes CCS is more 

expensive than either new coal-fired generation without CCS or 

new NGCC generation, it is competitive with new nuclear power, 

which is one of the other options often considered for providing 

new baseload power, and other low-GHG emitting generation 

technologies. A review of utility IRPs shows that a number of 

companies are considering new nuclear power as an option for new 

baseload generation capacity in lieu of new coal-fired 

generation with or without CCS, because they state it is a costeffective way to generate baseload electricity that addresses 

risks associated with potential future carbon liabilities. New 

fossil fuel-fired generation that includes CCS serves the same 

basic function as new nuclear power: providing baseload power 

with a lower carbon footprint. New coal-fired generation that 

incorporates partial CCS that is sufficient to meet the CO2

emission limitation that we are proposing in today’s action 

(1,100 lb CO2/MWh) would have a similar LCOE as a new nuclear 

power plant (about $103/MWh - $114/MWh). This indicates that, at 

the proposed emission limitation of 1,100 lb CO2/MWh, the cost of 

new coal-fired generation that includes CCS is reasonable today. 

Comment [A95]: In light of Fukushima, is this 

still accurate? Consider adding a footnote to 

acknowledge Fukushima context. 

Comment [A96]: Not unreasonable? 

in this rulemaking, we will use the 

“unreasonable” formulation, so that 

a control technology cannot be 

considered the “best system of 

emission reduction ... adequately 

demonstrated” if its costs are 

“unreasonable.”
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3. Costs of “Full capture” CCS 

As discussed in the Regulatory Impact Analysis (RIA)187 for 

this rulemaking, implementation of CCS to achieve 90 percent CO2

capture adds considerably to the levelized cost of electricity 

(LCOE) from a new SCPC or IGCC unit. The LCOE for a new SCPC and 

a new IGCC, both without CCS, are estimated to be $92/MWh and 

$97/MWh, respectively. The corresponding costs with 

implementation of “full capture” CCS are $147/MWh for the new 

SCPC unit and $136/MWh for the new IGCC unit. These costs exceed 

what project developers have been willing to pay for other low 

GHG-emitting baseload generating technologies (e.g., nuclear) 

that also provide energy diversity. For that reason, we do not 

believe that the costs of full implementation of CCS are 

reasonable at this time. 

4. Reasonableness of costs of partial CCS 

As noted, the current costs of coal, natural gas, and 

construction of coal-fired or natural gas-fired EGUs have led to 

little currently announced or projected new coal-fired 

generating capacity. This very likely reflects the large price 

differential between the cost of a new NGCC (cost of 

 

187 Regulatory Impact Analysis for the Standards of Performance 

for Greenhouse Gas Emissions for New Fossil Fuel-Fired Electric 

Utility Steam Generating Units and Stationary Combustion 

Turbines (available in the rulemaking docket EPA-HQ-OAR-2013-

0495) 
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electricity: $52/MWh at a natural gas price of $5/MMBtu) and 

SCPC without CCS (cost of electricity: $92/MWh) and IGCC without 

CCS (cost of electricity: $97/MWh), coupled with a leveling of 

demand for electricity and the recent increase in renewable 

sources. 

We observe that most of the industry appears to take the 

view that the price of natural gas will remain sufficiently low 

for at least a long enough period into the future that new 

natural-gas fired electricity generation will be less expensive 

than new coal-fired generation. As a result, in most cases, 

customers or utilities that contract for new generation are 

doing so for natural gas-fired generation. Long-term contracts 

for electricity supply are commonly for a 25-year period; thus, 

most of the industry appears to consider contracting for new 

natural gas-fired generation for a 25-year period to be the most 

economical of their choices. 

As shown in Table 4, we estimate that a new SCPC plant 

costs $92/MWh, which is $40/MWh, or about 77 percent higher than 

the new NGCC cost of $52/MWh. Limiting the emission rate to 

1,100 lb CO2/MWh (which can be achieved by adding partial CCS), 

without sale of captured CO2 for EOR, would add another $18/MWh 

to the cost of electricity, for a total of $110/MWh. Thus, the 

total additional cost to meet the proposed standard by 
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implementing partial capture CCS (without revenues from CO2 sales 

for EOR) is about half the additional cost of coal-fired 

generation, compared to natural-gas fired generation. 

We are aware of another segment of the industry, which 

includes electricity suppliers who have indicated a preference 

for new coal-fired generation to establish or maintain fuel 

diversity in their generation portfolio because their customers 

have expressed a willingness to pay a premium for that 

diversity. It appears these utilities and project developers see 

lower risks to long-term reliance on coal-fired generation and 

greater risks to long-term reliance on natural gas-fired 

generation, compared to the rest of the industry. We consider 

the costs of CCS to be reasonable for this segment of the 

industry as well. The additional costs of CCS for new SCPC of 

$18/MWh LCOE ($110/MWh for SCPC with partial CCS compared to 

$92/MWh for SCPC without CCS) are only about half as much as the 

additional costs that are would already need to be incurred to 

develop coal-fired electricity as compared to new NGCC 

generation ($92 MWH for SCPC without CCS compared to $52 MWh for 

NGCC at a natural gas price of $5/MMBtu). Moreover, it is 

possible that under these circumstances, the demand for the 

electricity would be inelastic with respect to the price because 

it may not depend on cost as much as on a demand for energy 
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diversity. These circumstances would be similar to the Portland 

Cement (1975) case, discussed above, in which the D.C. Circuit 

upheld NSPS controls that increased capital and operating costs 

by a substantial percentage because the demand for the goods was 

inelastic with respect to price, so that the industry could pass 

along the costs.188

In addition, we consider the costs of partial CCS to be 

reasonable because the industry can accommodate them. As noted, 

a segment of the industry consists of the several coal-fired EGU 

projects that already incorporate at least partial CCS. These 

projects, which are each progressing, include Kemper, TCEP, and 

HECA. Each is an IGCC plant that expects to generate profits 

from the sale of products that result from coal gasification, in 

addition to the sale of electricity. It is true that each of 

these projects has received DOE grants to encourage the 

development of CCS technology, but we do not consider such 

government subsidies to mean that the costs of CCS would 

otherwise be unreasonable. As we noted in the original proposal 

for this rulemaking,189 many types of electricity generation 

receive government subsidies. For example, nuclear power is the 

beneficiary of the Price-Anderson Act, which partially 

 

188 Portland Cement Ass’n v. EPA, 513 F.2d 506, 508 (D.C. Cir. 

1975). 

189 77 Fed. Reg. at 22,418/3. 
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indemnifies nuclear power plants against liability claims 

arising from nuclear incidents,190 and domestic oil and gas 

production,191 coal exploration and development,192 and renewable 

energy generation193 are each the beneficiary of Federal tax 

incentives. 

5. Opportunities to further reduce the costs of partial CCS 

a. Enhanced oil recovery 

While the reasons noted above are sufficient to justify the 

reasonableness of the costs of partial CCS, there are other 

reasons that lead to the same conclusion. One reason is the 

availability of EOR. As noted, EOR is being actively used in 

counties in various places in the U.S., and CO2 pipelines extend 

into those counties from, in some cases, hundreds of miles away. 

We consider areas in close proximity to active EOR locations, 

including the pipelines that extend into those locations, to be 

places where EOR is available. 

We recognize that, at present, certain locations are far 

enough away from either oilfields with EOR availability or 

 

190 See Duke Power Co. v. Carolina Environmental Study Group, 438 

U.S. 59 (1978). 

191 See, e.g., Internal Revenue Code §263. 192 See, e.g., “General Explanations of the Administration’s 

Fiscal Year 2013 Revenue Proposals,” pp. 120-24 

http://www.treasury.gov/resource-center/taxpolicy/Documents/General-Explanations-FY2013.pdf

193 See, e.g., Internal Revenue Code §45.

Comment [A97]: Is there a reference that could 

be used here to show existing subsidies. It appears 

this citation is about proposals. 
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pipelines to those oil fields that any coal-fired power plants 

that build in those locations would incur costs to build 

pipeline extensions that may render EOR non-economical. Those 

locations are relatively limited when legal or practical limits 

on building coal-fired power plants are taken into account. For 

example, some states with locations that are not located near 

EOR availability are not expected to have new coal-fired builds 

without CCS in any event, for legal or practical reasons. A 

number of States including: California, Washington, Oregon and 

New York preclude new coal-fired power plants without CCS. In 

the short term, other areas already have high reserve margins 

and/or have large renewable targets which push new decisions 

towards renewables and quick starting natural gas to provide 

backup to renewables over coal fired generation. 

In addition, it is important to note that coal-fired power 

plants that build in any particular location may serve demand in 

a wide area. There are many examples where coal-fired power 

generated in one state is used to supply electricity in other 

states. For instance, historically, nearly 40 percent of the 

power for the City of Los Angeles was provided from two coalfired power plants located in Arizona and Utah. In another 

example, Idaho Power, which serves customers in Idaho and 

Eastern Oregon, meets its demand in part from coal-fired power 
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plants located in Wyoming and Nevada. 

As a result, the geographic scope of areas in which EOR is 

available to defray the costs of CCS should be considered to be 

large. The costs provided in Table 4 show how the ability to 

sell CO2 for utilization in EOR can significantly affect the 

overall costs of the project. 

b. Government subsidies 

 In some instances, the costs of CCS can be defrayed by 

grants or other benefits provided by the DOE or the states. 

Although, for the reasons noted earlier, we consider the current 

costs of CCS even without subsidization to be reasonable, the 

availability of these governmental subsidies confirms the 

reasonableness of the costs. 

 The 2010 Interagency Task Force Report on CCS report 

described the DOE program as follows: 

The DOE is currently pursuing multiple 

demonstration projects using $3.4 billion of available 

budgetary resources from the American Recovery and 

Reinvestment Act in addition to prior year 

appropriations. Up to ten integrated CCS demonstration 

projects supported by DOE are intended to begin 

operation by 2016 in the United States. These 

demonstrations will integrate current CCS technologies 

with commercial-scale power and industrial plants to 

prove that they can be permitted and operated safely 

and reliably. New power plant applications will focus 

on integrating pre-combustion CO2 capture, transport, 

and storage with IGCC technology. Power plant retrofit 

and industrial applications will demonstrate 

Comment [A98]: Not unreasonable? 

in this rulemaking, we will use the 

“unreasonable” formulation, so that 

a control technology cannot be 

considered the “best system of 

emission reduction ... adequately 

demonstrated” if its costs are 

“unreasonable.”

Comment [A99]: How so? Because the overall 

economic impacts are more manageable on 

consumers? This seems like an incomplete 

explanation. 
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integrated post-combustion capture.194

DOE allocated some $3.4 billion for 5-10 projects, and has 

committed $2.2 billion for 5 projects to date. In addition, 

various other federal and state incentives are also available to 

many projects. The 2010 Interagency Task Force on CCS, in 

surveying all of the federal and state benefits available, 

concluded that the DOE grants, “plus ... federal loan guarantees, 

tax incentives, and state-level drivers, cover a large group of 

potential CCS options.” 195

In addition, regulatory programs may serve to defray the 

costs of CCS, including, for example, Clean Energy Standards or 

guaranteed electricity purchase price agreements.196

As noted above and in the April 2012 proposal, the need for 

subsidies to support emerging energy systems and new control 

technologies is not unusual. Each of the major types of energy 

used to generate electricity has been or is currently being 

supported by some type of government subsidy such as tax 

benefits, loan guarantees, low-cost leases, or direct 

expenditures for some aspect of development and utilization, 

 

194 Task Force Report on CCS, p. 76 195 Task Force Report on CCS, p. 76 196 See Center for Climate and Energy Solutions, “Financial 

Incentives for CCS” - 

http://www.c2es.org/sites/default/modules/usmap/pdf.php?file=838

0. 

Comment [A100]: Please elaborate further on 

these elements. More information should be 

provided. 
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ranging from exploration to control installation. This is true 

for fossil fuel-fired; as well as nuclear-, geothermal-, wind-, 

and solar-generated electricity.197 

c. The costs of CCS are expected to decrease 

The EPA reasonably projects that the costs of CCS will 

decrease over time as the technology becomes more widely used. 

Although, for the reasons noted earlier, we consider the current 

costs of CCS to be reasonable, the projected decrease in those 

costs further confirms their reasonableness. The D.C. Circuit 

case law that authorizes determining the “best” available 

technology on the basis of reasonable future projections 

supports taking into account projected cost reductions as a way 

to confirm the reasonableness of the costs.

As noted above, the D.C. Circuit, in the 1973 Portland 

Cement Ass’n v. Ruckelshaus case, stated that the EPA, in 

identifying the “best system of emission reduction ... adequately 

demonstrated,” may “look[] toward what may fairly be projected 

for the regulated future, rather than the state of the art at 

present....”198 In the 1999 Lignite Energy Council v. EPA case, the 

Court elaborated: 

 

197 77 Fed. Reg. at 22,418/3. 198 Portland Cement Ass’n v.Ruckelshaus, 486 F.2d 375, 391 (D.C. 

Cir. 1973), quoted in Lignite Energy Council v. EPA, 198 F.3d 

930, 933-34 (D.C. Cir. 1999). 

Comment [A101]: Not unreasonable? 

in this rulemaking, we will use the 

“unreasonable” formulation, so that 

a control technology cannot be 

considered the “best system of 

emission reduction ... adequately 

demonstrated” if its costs are 

“unreasonable.”
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Of course, where data are unavailable, EPA may 

not base its determination that a technology is 

adequately demonstrated or that a standard is 

achievable on mere speculation or conjecture....but EPA 

may compensate for a shortage of data through the use 

of other qualitative methods, including the reasonable 

extrapolation of a technology's performance in other 

industries.199

It is logical to read these statements in the D.C. Circuit case 

law to apply as well to the cost component of the “best system 

of emission reduction ... adequately demonstrated.” 

We expect the costs of CCS technologies to decrease. for 

several reasons. We expect that significant additional knowledge 

will be gained from deployment and operation of at least two new 

coal-fired generation projects that include CCS. These projects 

(the Southern Company’s Kemper County Energy Facility IGCC with 

CCS and the Boundary Dam CCS project on a conventional coalfired power plant in Canada) are currently under construction 

and are expected to commence operation next year. In addition 

there are several other CCS projects in advanced stages of 

development in the U.S. (e.g., the Texas Clean Energy Project, 

the Hydrogen Energy California Project, and the Future Gen 

 

199 Lignite Energy Council v. EPA, 198 F.3d 930, 934 (D.C. 

Cir. 1999). Based on this view that EPA may extrapolate 

from other industries, the Court in the Lignite Energy 

Council v. EPA case upheld a control technology as being 

“adequately demonstrated” for coal-fired industrial boilers 

because the technology was utilized by utility boilers. 

Comment [A102]: Any citations to provide 

further support? 
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project in Illinois) that may also provide additional 

information. In addition, research is underway to reduce CO2

capture costs and to improve performance. The DOE/NETL sponsors 

an extensive research, development and demonstration program 

that is focused on developing advanced technology options that 

will dramatically lower the cost of capturing CO2 from fossilfuel energy plants compared to today’s available capture 

technologies. The DOE/NETL estimates that using today’s 

available CCS technologies would add around 80 percent to the 

cost of electricity for a new pulverized coal plant, and around 

35 percent to the cost of electricity for a new advanced 

gasification-based plant (Note that these cost increases would 

be significantly less for the partial capture standard being 

proposed in today’s notice). The CCS research, development and 

demonstration program is aggressively pursuing efforts to reduce 

these costs to a less than 30 percent increase in the cost of 

electricity for PC power plants and a less than 10 percent 

increase in the cost of electricity for new gasification-based 

power plants.200 The large-scale CO2 capture demonstrations that 

are currently planned and in some cases underway, under the 

DOE’s initiatives, as well as other domestic and international 

 

200 DOE/NETL Carbon Dioxide Capture and Storage RD&D Roadmap, 

U.S. Department of Energy National Energy Technology Laboratory, 

December 2010.
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projects, will generate operational knowledge and enable 

continued commercialization and deployment of these 

technologies. 

Gas absorption processes using chemical solvents, such as 

amines, to separate CO2 from other gases have been in use since 

the 1930s in the natural gas industry and to produce food and 

chemical grade CO2. The advancement of amine-based solvents is an 

example of technology development that has improved the cost and 

performance of CO2 capture. Most single component amine systems 

are not practical in a flue gas environment as the amine will 

rapidly degrade in the presence of oxygen and other 

contaminants. The Fluor Econamine FGSM process uses a 

monoethanolamine (MEA) formulation specially designed to recover 

CO2 and contains a corrosion inhibitor that allows the use of 

less expensive, conventional materials of construction. Other 

commercially available processes use sterically hindered amine 

formulations (for example, the Mitsubishi Heavy Industries KS-1 

solvent) which are less susceptible to degradation and corrosion 

issues. The DOE/NETL and private industry are continuing to 

sponsor research on advanced solvents (including new classes of 

amines) to improve the CO2 capture performance and reduce costs. 

 Significant reductions in the cost of CO2 capture would be 

consistent with overall experience with the cost of pollution 
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control technology. A significant body of literature suggests 

that the per-unit cost of producing or using a given technology 

declines as experience with that technology increases over 

time,201 and this has certainly been the case with air pollution 

control technologies. Reductions in the cost of air pollution 

control technologies as a result of learning-by-doing, 

reductions in financial premiums related to risk, research and 

development investments, and other factors have been observed 

over the decades. 

In addition, we note that the 2010 Interagency Task Force 

on CCS report recognized that CCS would not become more widely 

available without a regulatory framework that promoted CCS or a 

strong price signal for CO2. Today’s action is an important 

component in developing that framework. 

G. Promotion of technology

 

201 These studies include John M. Dutton and Annie Thomas, 

"Treating Progress Functions as a Managerial Opportunity," 2, 

235-247; Dennis Epple, Linda Argote, and Rukmini Devadas, 

"Organizational Learning Curves: A Method for Investigating 

Intra-plant Transfer of Knowledge Acquired Through Learning by 

Doing," Organizational Science, Vol. 2, No. 1, February 1991; 

International Energy Agency, Experience Curves for Energy 

Technology Policy, 2000; and Paul L. Joskow and Nancy L. Rose, 

"The Effects of Technological Change, Experience, and 

Environmental Regulation on the Construction Cost of CoalBurning Generating Units," RAND Journal of Economics, Vol. 

16,Issue 1, 1-27, 1985. See discussion in “The Benefits and 

Costs of the Clean Air Act from 1990 to 2020,” U.S. EPA, Office 

of Air and Radiation, April 2011.

Comment [A103]: It would be helpful to cite 

relevant literature to support the statement. 
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It is clear that identifying partial CCS as the BSER 

promotes the utilization of CCS because any new fossil fuelfired utilty boiler or IGCC unit will need to install partial 

capture CCS in order to meet the emission standard. Particularly 

because the technology is relatively new, additional utilization 

is expected to result in improvements in the performance 

technology and in cost reductions. Moreover, identifying partial 

capture CCS as the BSER will encourage continued research and 

development efforts, such as those sponsored by the DOE/NETL. In 

contrast, not identifying partial CCS as the BSER could 

potentially impede further utilization and development of CCS. 

It is important to promote deployment and further development of 

CCS technologies because they are the only technologies that are 

currently available or are expected to be available in the 

foreseeable future that can make meaningful reductions in CO2

emissions from fossil fuel-fired utility boilers and IGCC units. 

Identifying partial CCS as the BSER also promotes further 

use of EOR because, as a practical matter, we expect that new 

fossil fuel-fired EGUs that install CCS will generally make the 

captured CO2 available for use in EOR operations. The use of EOR 

lowers costs for production of domestic oil, which promotes the 

important goal of energy independence. 

H. Nationwide, longer-term perspective
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As noted, the D.C. Circuit in Sierra Club held: 

The language of [the definition of “standard of 

performance” in] section 111 ... gives EPA authority 

when determining the best ... system to weigh cost, 

energy, and environmental impacts in the broadest 

sense at the national and regional levels and over 

time as opposed to simply at the plant level in the 

immediate present.202

Considering on “the national and regional levels and over 

time” the criteria that go into determining the “best system of 

emission reduction ... adequately demonstrated” also supports 

identifying partial CCS as that best system because doing so 

would not have adverse impacts on the power sector, national 

electricity prices, or the energy sector. 

1. Structure of the power sector 

Identifying partial CCS as the BSER for new fossil fuelfired utility boilers and IGCC units is consistent with the 

current and projected future structure of the power sector. As 

noted, we project that in light of the current and projected 

trends in coal and natural gas costs, virtually all new electric 

generating capacity will employ NGCC technology or renewable 

energy, and very little new capacity will be coal-fired. 

As noted above, the recent history of solid fossil fuelfired projects suggest that these new coal-fired builds, if they 

 

202 Sierra Club v. Costle, 657 F.2d at 330.
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occur, may (i) consist of an IGCC unit, include features such as 

sale of additional byproducts (e.g., plants such as the Texas 

Clean Energy Project, which intents to manufacture fertilizer 

products for sale and sell captured CO2 for EOR in addition to 

selling electricity), use of lower cost opportunity fuels (such 

as petcoke proposed to be used at the Hydrogen Energy California 

facility) and/or rely on additional local regulatory drivers 

(such as California’s AB-32 program which incentivizes lower CO2

generating technologies), all of which would be designed to 

offset enough of the additional coal-related costs to be able to 

compete with natural-gas fired electricity in the marketplace; 

and (ii) those that are designed to offer fuel diversity to a 

group of customers that are willing to pay a premium in 

electricity prices (such as the Power4Georgians project in 

Washington County, Georgia). 

Projects in the first category would by definition already 

include at least partial CCS and, as a result, would be affected 

by this rule to only a limited extent. Projects in the second 

category would be more affected, but developers of these 

projects would nevertheless have several options. They could 

pursue coal with CCS and possibly rely on cost savings from EOR 

or on their customers’ willingness to pay a higher premium. 

Alternatively, they could choose a different generation 
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technology (most likely natural gas). Even if they chose a 

different generation technology, the small number of these 

sources and the fact that the basic demand for electricity would 

still be met would limit the impact of this rule on the power 

sector. 

2. Impacts on nationwide electricity prices. 

Identifying partial CCS as the BSER for fossil fuel-fired 

utility boilers and IGCC units will not have significant impacts 

on nationwide electricity prices. The reason is that the 

additional costs of partial CCS will, on a nationwide basis, be 

small because no more than a few new coal-fired projects are 

expected, and because, as noted, at least some of these can be 

expected to incorporate CCS technology in any event. It should 

be noted that the computerized model the EPA relies on to assess 

energy sector and nationwide impacts – the Integrated Planing 

Model (IPM) – does not forecast any new coal-fired EGUs through 

2020. Based on these IPM analyses, the RIA for this rulemaking 

concludes that the proposed standard of 1,100 lb of CO2/MWh for 

new fossil fuel-fired EGUs, which is based on partial CCS as the 

best demonstrated system, does not create any costs. 

3. Energy considerations 

Identifying partial CCS as the BSER for new fossil fuelfired utility boilers and IGCC units is consistent with 

Comment [A104]: EPA may want to consider 

pointing out in this section that the availability of 

natural gas-fired plants to meet electricity generation 

needs at a reasonable cost also serves as a backstop 

against any large economic/energy impacts. 
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nationwide energy considerations because it will not have 

adverse effects on the structure of the power sector, will 

promote fuel diversity over the long term, and will not have 

adverse effects on the supply of electricity. 

Identifying partial CCS as the BSER will not have adverse 

impacts on the structure of the power sector because, as noted, 

for reasons related to the cost differential between natural 

gas-fired and coal-fired electricity, very little, if any, new 

coal-fired EGUs are projected to be built, and at least some of 

those that may be built would be expected to include CCS 

technology in any event. 

In addition, identifying partial CCS as the BSER for coal 

will be beneficial to coal-fired electric generation, and 

therefore fuel diversity, over the long term. This is because 

IdentifyingiIdentifying partial CCS as BSER eliminates 

uncertainty as to future control obligations for coal-fired 

capacity. Any Currently, any new coal-fired source that 

constructs without CCS faces the risk that future state or 

federal controls may require carbon capture, which would require 

the source to retrofit to CCS, which, in turn, is a particularly 

more expensive proposition. This risk is heightened because 

power plants are generally long-lived and the risk likelihood of 

future carbon limitations can be expected to remain throughout 
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that period. Any new coal-fired source that constructs with 

partial-capture CCS will achieve some level of CO2 emissions 

reductions, which lowers the risk of future liability., whichand

may provide competitive advantages over higher emitting sources.

Because at present, new electric generating construction is 

primarily natural gas-fired, benefiting new coal-fired capacity, 

at least over the long term, protects fuel diversity. 

Moreover, even if requiring CCS adds sufficient costs to 

prevent a new coal-fired plants from constructing in a 

particular part of the country due to lack of available EOR to 

defray the costs, or, in fact, from constructing at all, a new 

NGCC plant can be built to serve the electricity demand that the 

coal-fired plant would otherwise serve. Thus, the present 

rulemaking does not prevent basic electricity demand from being 

met, and thus does not have an adverse effect on the supply of 

electricity. As noted above, the EPA is authorized to promulgate 

standards of performance under CAA §111 that may have the effect 

of precluding construction of sources in certain geographic 

locations or in certain locations. 

4. Environmental considerations 

Identifying partial CCS as the BSER for coal-fired power 

plants protects the environment by preventing large amounts of 

CO2 emissions from new fossil fuel-fired utility boilers and IGCC 
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units. As noted, CCS is the only technology available at present 

or within the foreseeable future that provides meaningful 

reductions in the amount of CO2 emissions in this sector. 

I. Consistency with purposes of CAA section 111

 Identifying partial CCS as the BSER is also consistent with 

the purposes of CAA section 111, which, as discussed above, 

including includes avoiding giving any state a competitive 

advantage, reducing emissions as much as possible, obviating any 

need for retrofits on new sources, and promoting technology 

development.203

 One purpose of CAA section 111 is that “[t]he standards [of 

performance] must not give a competitive advantage to one State 

over another in attracting industry.”204 The 1,100 lb CO2/MWh 

standard that the EPA proposes in this rulemaking applies to all 

new coal-fired power plants in all geographic locations. As a 

result, there is nothing on the face of the standard that would 

provide a competitive advantage to one state over another in 

attracting industry. While it is true that some states may offer 

more attractive opportunities for CCS – because, for example, of 

 

203 Sierra Club v. Costle, 657 F.2d at 325 & n.83 (quoting 44 

Fed.Reg. 33,580, 33,581/3-33,582/1 (EPA summary of the six 

purposes identified in the 1977 House Committee Report, H.R. 

Rep. No. 95-294, 95th Cong., 1st Sess. 184-86 (1977), 4 L.H. at 

2651-53)). 

204 Sierra Club, 657 F.2d at 325 & n. 83. 
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greater availability or value for EOR – power plant siting by 

its nature generally favors certain locations over others. For 

example, coal-fired power plants usually require a large source 

of water, which favors certain locations over others. The fact 

that CCS adds another siting consideration does not mean that it 

unfairly benefits certain States at the expense of others, so 

far as the purposes of section 111 are concerned. 

 A second purpose of section 111 is “reducing emissions as 

much as practicable.”205 For the reasons noted above, identifying 

partial CCS as the BSER meets this purpose. 

A third purpose of section 111 is, “to the extent practical 

force the installation of all the control technology that will 

ever be necessary on new plants at the time of construction when 

it is cheaper to install, thereby minimizing the need for 

retrofit in the future....”206 As noted above, identifying partial 

CCS as BSER meets this purpose by achieving CO2 emissions 

reductions. In contrast, identifying highly efficient SCPC or 

IGCC without at least partial CCS as the BSER would leave 

sources vulnerable to retrofit obligations if CO2 emissions 

reduction requirements are imposed in the future. 

 

205 Id. As noted, Congress identified this purpose in the context 

of NAAQS pollutants, but this purpose applies to greenhouse 

gases as well.

206 Id. 
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A fourth purpose of section 111 is “The standards should be 

stringent in order to force the development of improved 

technology.”207 For the reasons noted above, identifying partial 

CCS as the BSER meets this purpose. 

J. Deference

As noted above, the D.C. Circuit has held that it will 

grant a high degree of deference to the EPA in determining the 

appropriate standard of performance. Because determining the 

BSER for coal-fired power plants requires balancing several 

factors, including on a nationwide basis and over time, the 

EPA’s determination that partial CCS is the BSER should be 

granted a high degree of deference. 

K. CCS and BSER in locations where costs are too high to 

implement CCS

As noted above, under CAA §111, an emissions standard may 

meet the requirements of a “standard of performance” even if it 

cannot be met by every new source in the source category that 

would have constructed in the absence of that standard. As also 

noted above, the EPA’s analysis for this proposal indicates that 

coal-fired power plants that would otherwise construct in the 

absence of the standards in this proposal may still do so. 

However, we recognize that there may be some geographic 

 

207 Id. 
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locations where EOR is not practicably available, so that in 

those locations, the higher costs of CCS may tilt the economics 

against new coal-fired construction. Even in this case, the 

standard would remain valid under CAA §111, particularly because 

the basic demand for electricity could still be served by NGCC, 

which this rulemaking determines to be the “best system” for 

natural gas-fired power plants. 

L. Compliance period

1. 12-operating-month period 

Under today’s proposal, sources must meet the 1,100 lb 

CO2/MWh limit on a 12-operating-month rolling basis. This 12-

operating-month period is important due the inherent variability 

in power plant GHG emissions rates. Establishing a shorter 

averaging period would necessitate establishing a standard to 

account for the conditions that result in the lowest efficiency 

and therefore the highest GHG emissions rate. 

EGU efficiency has a significant impact on the source’s GHG 

emission rate. By comparison, efficieny has a smaller impact on 

the emissions rate for criteria or hazardous air pollutants 

(HAPs). This is because control of criteria pollutants and HAPs 

often involves the use of a pollution control device that 

results in significant reductions, often greater 90 percent. In 

this situation, the performance of the specific pollution 
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control device impacts the emissions rate much more than the EGU 

efficiency. In this situation, efficiency is a key factor in 

determining the emissions rate. 

EGU efficiency can vary significantly from month to month 

throughout the year. For example, high ambient temperature can 

negatively impact the efficiency of combustion turbine engines 

and steam generating units. As a result, an averaging period 

shorter than 12 operating-months would require us to set a 

standard that could be achieved under these conditions. This 

standard could potentially be high enough that it would not be a 

meaningful constraint during other parts of the year. In 

addition, operation at low load conditions can also negatively 

impact efficiency. It is likely that for some short period of 

time an EGU will operate at an unusually low load. A short 

averaging period that accounts for this operation would again 

not necessarily meaningfully constrain for typical loads. 

On the other hand, a 12-operating-month rolling average 

explicitly accounts for variable operating conditions, allows 

consistent emissions rate averaging, allows for a more 

protective standard and decreased compliance burden, and 

simplifies compliance for state permitting authorities. Because 

the 12-operating-month rolling average can be calculated each 

month, this form of standard makes it possible to assess 
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compliance and take any needed corrective action on a monthly 

basis. The EPA proposes that it is not necessary to have a 

shorter averaging period for CO2 from these sources because the 

effect of GHGs on climate change depends on global atmospheric 

concentrations which are dependent on cumulative total emissions 

over time, rather than hourly or daily emissions fluctuations or 

local pollutant concentrations. Unlike for emissions of criteria 

and hazardous air pollutants, we do not believe that there are 

not measureable implications to health or environmental impacts 

from short-term higher CO2 emission rates as long as the 12-month 

average emissions rate is maintained. 

We solicit comment on, in the alternative, basing 

compliance requirements on an annual (calendar year) average 

basis. 

2. 60-operating-month compliance period compliance period 

Under today’s proposal, new fossil fuel-fired boilers and 

IGCC units will have the option to alternatively meet an 

emission standard on a 60-operating-month rolling basis. 

The EPA has previously offered sources optional, longerterm emission standards that are stricter than the primary 

emissions standard in exchange for the thecombination with a

longer averaging period. We are proposing that this alternative 

emission limit should be between 950 – 1,050 lb CO2/MWh and we 

Comment [A105]: Appears this should be 

omitted. 

Comment [A106]: “in exchange for” sounds like 

a negotiation. 
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are requesting comment on what the final numerical standard 

should be (within that range) such that the 60-operating-month 

standard would be as stringent as or more stringent than the 12-

operating-month standard. 

We are also request comment on an appropriate 12-operatingmonth standard that owners/operators electing to comply with the 

60-operating-month standard would have to comply with. This 

standard would be numerically between the alternate 12-

operating-month standard and an emissions rate of a coal-fired 

EGU without CCS (e.g., 1,800 lb CO2/MWh). This shorter term 

standard would be more easily enforced and assure adequate 

emission reductions. 

This 60-operating-month period offers increased operational 

flexibility and will tend to dampen short-term emission 

excursions, which may be warranted especially at the initial 

startup of the facility and the CCS system. 

M. Geologic sequestration

1. Overview 

We expect that for the immediate future, virtually all of 

the CO2 captured at EGUs will be injected underground for longterm geologic sequestration at sites where enhanced oil recovery 

is also occurring. There is an existing regulatory framework for 

geologic sequestration and enhanced oil recovery activities. We 
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intend to rely upon this existing framework to verify that the 

CO2 captured from an affected unit is injected underground for 

long-term containment. More specifically, as discussed in 

section 3, the EPA is proposing to build from the existing 

Greenhouse Gas Reporting Program 40 CFR Part 98 to track that 

the captured CO2 is geologically sequestered. 

In addition, we recognize that types of CO2 storage 

technologies other than geologic sequestration are under 

development (e.g. precipitated calcium carbonate, etc). EGUs may 

use other types of CO2 storage technologies to meet the standard, 

once the EPA has approved its use, including methods for 

reporting, monitoring, and verifying long-term CO2 storage. We 

welcome comments on an appropriate mechanism for making this 

determination. 

2. Existing regulatory framework for CCS 

As noted, the EPA expects that for the immediate future, 

captured CO2 from affected units will be injected underground for 

geologic sequestration at sites where EOR is occurring. 

Underground injection is currently the only technology available 

that can accommodate the large quantities of CO2 captured at 

EGUs, and EOR provides an associated economic incentive and 

benefit. The threeTthree solid-fuel fired EGU projects 

Formatted: Subscript
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incorporating CCS that have progressed the furthest – Kemper, 

TCEP, and HECA – all include utilization of captured CO2 for EOR. 

The EPA has promulgated, or recently proposed, several 

rules to protect underground sources of drinking water and track 

the total amount of CO2 that is supplied to the economy and 

injected underground for geologic sequestration. First, the 

EPA’s Underground Injection Control (UIC) Class VI rule, 

established under authority of the Safe Drinking Water Act, sets 

requirements to ensure that geologic sequestration wells are 

appropriately sited, constructed, tested, monitored, and closed 

in a manner that ensures protection of underground sources of 

drinking water.208 The UIC Class VI regulations contain 

monitoring requirements to protect underground sources of 

drinking water, including the development of a comprehensive 

testing and monitoring plan. This includes testing of the 

mechanical integrity of the injection well, ground water 

monitoring, and tracking of the location of the injected CO2 and 

the associated area of elevated pressure using both direct and 

indirect methods, as appropriate. Projects are also required to 

conduct extended post-injection monitoring and site care to 

track the location of the injected CO2 and monitor subsurface 

 

208

http://water.epa.gov/type/groundwater/uic/wells_sequestration.cf

m

Comment [A107]: Consider whether this is 

necessary in the context of describing the existing 

regulatory framework 
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pressures until it can be demonstrated that there is no longer a 

risk of endangerment to underground sources of drinking water. 

UIC Class II wells inject fluids associated with oil and 

natural gas production and the storage of liquid hydrocarbons. 

Most of the injected fluid is salt water, which is brought to 

the surface in the process of producing (extracting) oil and gas 

and subsequently re-injected. In addition, other fluids, 

including CO2, are injected to enhance oil and gas production. 

Class II regulations include site characterization, well 

construction, operating, monitoring, testing, reporting, 

financial responsibility, and closure requirements to prevent 

endangerment of underground sources of drinking water. Wells 

that inject CO2 underground for enhanced oil or gas recovery may 

be permitted as UIC Class II or Class VI wells. However, the 

designation of the appropriate well class depends, principally, 

on the risks posed or changes in the risks posed to underground 

sources of drinking water by a specific injection operation. 

Second, the Greenhouse Gas Reporting Program (GHGRP) covers 

sources that generate electricity (40 CFR Part 98 subpart D), 

sources that supply CO2 to the economy (40 CFR Part 98, subpart 

PP) and sources that inject CO2 underground for geologic 

sequestration (40 CFR Part 98, subpart RR). Subpart D owners or 

operators of facilities that contain electricity-generating 
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units must report emissions from electricity-generating units 

and all other source categories located at the facility for 

which methods are defined in Part 98.209 Owners or operators are 

required to collect emission data; calculate GHG emissions; and 

follow the specified procedures for quality assurance, missing 

data, recordkeeping, and reporting. 

Subpart PP provides requirements for quantifying CO2

supplied to the economy.210 Affected units that capture CO2 to 

inject underground or supply offsite, are subject to all of the 

requirements under Subpart PP of the GHG Reporting Program, 

which relates to suppliers of CO2. Specifically, Subpart PP 

requires suppliers of CO2 that meet certain applicability 

requirements to report the mass of CO2 captured from production 

process unit(s) for the purposes of supplying CO2 for commercial 

applications or that capture and maintain custody of a CO2 stream 

in order to sequester or otherwise inject underground. CO2

suppliers are required to report the annual quantity of 

CO2transferredCO2 transferred offsite and for what end use, 

including geologic sequestration. 

Subpart RR requires that facilities meeting the source 

category definition (40 CFR 98.440) for any well or group of 

 

209 http://www.epa.gov/ghgreporting/reporters/subpart/d.html 210 http://www.epa.gov/ghgreporting/reporters/subpart/pp.html
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wells to report basic information on the amount of CO2 received 

for injection; develop and implement an EPA-approved monitoring, 

reporting, and verification (MRV) plan; and report the amount of 

CO2 sequestered using a mass balance approach and annual 

monitoring activities. The MRV plan must be submitted and 

approved by the EPA and revised if necessary over time according 

to 40 CFR 98.448(d). The subpart RR MRV plan must include five 

major components: 

 A delineation of the maximum monitoring area (MMA) and the 

active monitoring area (AMA). 

 An identification and evaluation of the potential surface 

leakage pathways and an assessment of the likelihood, 

magnitude, and timing, of surface leakage of CO2 through 

these pathways in the MMA. 

 A strategy for detecting and quantifying any surface 

leakage of CO2 in the event leakage occurs. 

 An approach for establishing the expected baselines for 

monitoring CO2 surface leakage. 

 A summary of considerations made to calculate site-specific 

variables for the mass balance equation. 

More information on the MRV plan is available in the 

Technical Support Document (TSD) for the subpart RR final rule 

(75 FR 75065). 
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If an enhanced oil and gas recovery project holds a UIC 

Class VI permit, it is required to report under subpart RR. If 

the project holds a UIC Class II permit and is injecting a CO2

stream underground, it is not subject to subpart RR, but the 

owner or operator may choose to opt-in to subpart RR. Sources 

reporting under subpart RR, whether they are UIC Class VI or 

Class II well(s), must follow the same set of requirements. 

As stated in the preamble to the final subpart RR rule: 

“while requirements under the UIC program are focused 

on demonstrating that USDWs are not endangered as a 

result of CO2 injection into the subsurface, 

requirements under the GHG Reporting Program through 

40 CFR part 98, subpart RR will enable EPA to verify 

the quantity of CO2 that is geologically sequestered 

and to assess the efficacy of GS as a mitigation 

strategy. Subpart RR achieves this by requiring 

facilities conducting GS to develop and implement a 

MRV plan to detect and quantify leakage of injected CO2

to the surface in the event leakage occurs and to 

report the amount of CO2 geologically sequestered using 

a mass balance approach, regardless of the class of 

UIC permit that a facility holds.” (75 FR 75060) 

The Internal Revenue Service relies on subpart RR 

compliance to verify geologic sequestration for the 45Q tax 

credit. As stated in the preamble to the final subpart RR 

rule: 

“EPA notes that the Internal Revenue Service 

(IRS) published IRS Notice 2009–83 7 to provide 

guidance regarding eligibility for the Internal 

Revenue Code section 45Q credit for CO2 sequestration, 

computation of the section 45Q tax credit, reporting 

requirements for taxpayers claiming the section 45Q 
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tax credit, and rules regarding adequate security 

measures for secure GS. As clarified in the IRS 

guidance, taxpayers claiming the section 45Q tax 

credit must follow the appropriate UIC requirements. 

The guidance also clarifies that taxpayers claiming 

section 45Q tax credit must follow the MRV procedures 

that are being finalized under 40 CFR part 98, subpart 

RR in this final rule.” (75 FR 75060) 

Third, the EPA proposed a rule that would conditionally 

exclude CO2 streams from the definition of hazardous waste under 

RCRA, where these streams are being injected for purposes of 

geologic sequestration, into a UIC Class VI well and meet other 

conditions.211 The rationale for the rule was that any CO2 stream 

that would otherwise be defined as hazardous waste, need not be 

managed as hazardous waste, provided it is managed under other 

regulatory programs that address the potential risks to human 

health and the environment that these materials may pose. 

The EPA notes that compliance with the standard of 1,100 lb 

CO2/MWh is determined exclusively by the tons of CO2 captured by 

the emitting EGU. The tons of CO2 sequestered by the repository 

are not part of that calculation. However, to verify the amount 

of tons of CO2 captured at the emitting EGU are safely and 

effectively sequestered, we are building on existing regulatory 

requirements under Subpart RR, all CO2 that is geologically 

sequestered at the site of the EGU facility must be reported 

 

211 76 Fed. Reg. 48073 (Aug. 8, 2011) 

Formatted: Subscript
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under subpart RR by the owner or operator of the EGU. 

Additionally, where the captured CO2 is sent offsite, it must be 

transferred to an entity that is reporting under Subpart RR. 

This provides assurance that the tons of CO2 captured are 

transferred to a repository which provides assurance of long 

term containment integrity. Under today’s proposal, that type of 

repository is a Class II or Class VI UIC well which would report 

its GHG emissions under subpart RR. 

The EPA acknowledges that there can be downstream losses of 

CO2 after capture. The EPA expects these losses to be modest with 

incentives due to the market use of CO2 as a purchased product. 

There remains an issue of whether the standard itself should be 

adjusted to reflect these downstream losses. The EPA is not 

proposing to do so. Moreover, the EPA wishes to encourage rather 

than discourage EOR using captured CO2 since the practice makes 

CCS itself more economic and thus promotes use of the technology 

on which the proposed standard is based. See Sierra Club v. 

Costle, 657 F. 2d at 347 (one purpose of section 111 standards 

is to promote expanded use and development of technology). 

We also emphasize that today’s proposal does not involve 

regulation of any downstream recipients of captured CO2. That 

is, the regulatory standard applies exclusively to the emitting 

EGU, not to any downstream user or recipient of the captured CO2

Formatted: Subscript

Comment [A108]: How will this requirement be 

enforced? Is the requirement for CO2 to be reported 

under the GHG reporting program an explicit part of 

the “standard of performance” and therefore 

enforceable like any other part of the standard? 

Comment [A109]: At what points can 

downstream losses occur? Are there multiple? 

Also, are there any lossess associated with onsite 

storage? 
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(whether the captured CO2 is sold for productive use or otherwise 

managed). The requirement that the emitting entity assure that 

captured CO2 is managed at an entity subject to the GHG reporting 

rules is thus exclusively an element of enforcement of the EGU 

standard. Similarly, the existing regulatory requirements 

applicable to geologic sequestration are not part of the 

proposed NSPS. The standard is a numeric value, applicable 

exclusively to the emitting EGU. The requirement that the EGU 

use the repository reporting pursuant to subpart RR and that the 

repository be a Class II or VI UIC well is a means of assuring 

the integrity of the stack emission limit applicable to the 

emitting EGU. 

3. Proposal 

a. Geologic Sequestration 

Together, the framework just described help create a 

consistent national framework to ensure the safe and effective 

deployment of geologic sequestration technologies. Importantly, 

a key component of this framework- the Greenhouse Gas Reporting 

Program- provides a mechanism for new generating units that 

supply captured CO2 for geologic sequestration (including CO2

sequestered while oil and gas recovery is occurring), to help 

demonstrate they are achieving the required emission reductions. 

Therefore, the EPA is proposing that any affected unit that 

Comment [A110]: ?? suggest omitting. 

Consider rephrasing sentence: The NSPS proposal 

builds on and is consistent with existing framework 

for safe and effective GS. 

Comment [A111]: Is this potentially overstating 

the extent of the requirements, given that long term 

sequestration is not actually part of what’s 

“required” (just sending the CO2 to a facility that 

reports)? 
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employs CCS technology which captures enough CO2 to meet the 

1,100 lb/MWh standard must report, under 40 CFR Part 98 Subpart 

RR, if the captured CO2 is injected onsite. If the captured CO2

is sent offsite, then the facility injecting the CO2 underground 

must report under 40 CFR Part 98 subpart RR. Regardless of the 

injection site, the affected source must still comply with 40 

CFR Part 98 Subpart PP. As noted above, owners and operators of 

projects that inject CO2 underground and that are permitted under 

a UIC Class VI permit are required to comply with subpart RR. 

The practical impact of our proposal would be that owners and 

operators of projects injecting CO2 underground that are 

permitted under UIC Class II and that receive CO2 captured from 

EGUs to meet the proposed performance standard will also be 

required to submit and receive approval of a subpart RR MRV plan 

and report under subpart RR. Many of these EOR facilities are 

already familiar with reporting under Subpart UU of the 

Greenhouse Gas Reporting Program. 

To provide certainty and verify that CO2 captured at an 

affected unit is geologically sequestered, today’s action relies 

upon the existing regulatory framework the EPA already has in 

place under the Greenhouse Gas Reporting Program 40 CFR Part 98. 

As discussed in the previous section, there are 3 relevant 

subparts (subpart D, PP and RR) under 40 CFR Part 98, that can 
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provide an appropriate reporting and verification mechanism for 

demonstrating that any unit subject to these proposed standards 

complies with them. The EPA requires electric generating units 

to report CO2 emissions under subpart D. Facilities that capture 

CO2 are required to report quantities of CO2 captured and 

injected on site or transferred off-site under subpart PP. 

Facilities that inject CO2 underground for permanent 

sequestration report under subpart RR. Through these Greenhouse 

Gas Reporting Program provisions, the EPA and other regulatory 

authorities can track geologic sequestration conducted to meet 

the performance standard. 

In order to use the GHGRP for compliance tracking, the EPA 

proposes that any affected unit that uses CCS to comply with the 

emissions limit must demonstrate that CO2 is geologically 

sequestered through the Greenhouse Gas Reporting Program. In 

order to do that, we are proposing that a facility capturing CO2

from an affected unit, and therefore subject to 40 CFR Part 98 

subpart PP, must provide additional information in their subpart 

PP annual report including 1) the electronic Greenhouse Gas 

Reporting Tool identification (e-GGRT ID) of the facility with 

the electric generating unit from which CO2 was captured, 2) the 

e-GGRT ID(s) for, and mass of CO2 transferred to, each geologic 

sequestration site reporting under subpart RR. This proposed 

Comment [A112]: This seems somewhat 

unclear. Must the affected unit demonstrate 

sequestration or just that it goes to a facility that 

reports under the GHG reporting program? This 

seems to imply the former, but doesn’t seem 

consistent with the explanation above. 
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amendment to the Greenhouse Gas Reporting Program provides a 

transparent and consistent method to track geologic 

sequestration used to meet the performance standard without 

significantly increasing burden on the affected sources. If the 

unit does not report under PP and comply with these proposed 

requirements, it will be considered in noncompliance with 

today’s proposal. 

The approach proposed today relies on the existing 

Greenhouse Gas Reporting framework to ensure that CO2 captured at 

an affected unit is transferred to a facility reporting geologic 

sequestration, and it does not impose any additional 

requirements for an affected unit to demonstrate how the 

captured CO2 is transferred to a facility that is compliant with 

40 CFR 98 subpart RR. We seek comment on whether there should 

be such requirements and suggestions for what those might 

include. 

b. Alternatives to geologic sequestration 

In the development of this proposal, the EPA has identified 

some potential alternatives to geologic sequestration, including 

but not limited to CO2 stored in precipitated calcium carbonate 

and certain types of cement. The EPA solicits comment on whether 

these and other alternatives to geologic sequestration 

permanently store CO2 (so that the stack standard is assured of 

Comment [A113]: As noted above, this seems to 

imply that the amount of CO2 sequestered is part of 

the performance standard, but that doesn’t seem to 

be consistent with what is explained elsewhere in 

this section. 
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achieving its object—to capture CO2 and prevent its atmospheric 

release) and if they are technically available for EGUs to meet 

the performance standard. Consideration of how these 

alternatives could meet the performance standard involves 

understanding the ultimate fate of the captured CO2 and the 

degree to which the method permanently isolates the CO2 from the 

atmosphere, as well as existing methodologies to verify this 

permanent storage. The EPA proposes that alternatives to 

geologic sequestration could not be used until the EPA finalizes 

a mechanism to demonstrate that a non-CCS technology would 

result in permanent storage of CO2. The EPA believes that the 

number of cases where an EGU would seek to comply with the 

performance standard through an alternative to CCS will be very 

few. However, the EPA wishes to encourage development of 

alternatives to geologic sequestration that could help offset 

the cost of CO2 capture.

c. Drafting Prevention of Significant Deterioration (PSD)

permits for affected sources using geologic sequestration

In most cases, sources that are subject to this NSPS will 

also be a major source or major modification under PSD and 

required to obtain a PSD permit prior to commencing 

construction. A permit is the legal tool used to establish all 

the source limitations deemed necessary by the reviewing agency 

Comment [A114]: Has EPA demonstrated that 

GS meets this standard? 
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during review of the permit application, and is the primary 

basis for enforcement of PSD requirements. A well written 

permit reflects the outcome of the permit review process 

and clearly defines what is expected of the source. The permit 

must be a "stand-alone" document that: (1) identifies the 

emissions units to be regulated; (2) establishes emissions 

standards or other operational limits to be met; (3) specifies 

methods for determining compliance and/or excess emissions, 

including reporting and recordkeeping requirements; and 

(4) outlines the procedures necessary to maintain continuous 

compliance with the emission limits. 

As noted in the "Implications for PSD and Title V programs" 

section of this preamble, some states have authority to issue 

PSD permits. In other cases, the EPA issues the permit. States 

with approved permitting programs have some discretion in making 

permit decisions and including the necessary conditions of the 

permit to ensure the enforceability of the permit. 

Compliance with the NSPS emissions standard is determined 

exclusively by evaluating emissions of CO2 at the EGU. To this 

end, section 60.5520 of this proposed rule, titled “What CO2

emissions standard must I meet?”, reads:

For each affected EGU subject to this subpart, you 

must not discharge from the EGU into the atmosphere 

any gases that contain CO2 in excess of the applicable 

CO2 emissions standard specified in Table 1 to this 
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subpart. Each CO2 emissions standard has a minimum of 

two significant digits. 

The EPA believes it is important to clarify the key 

components that should be included in a PSD permit. While we 

recognize that permit conditions may vary from state to state, 

we believe the following general condition areas of a permit 

would adequately show that the source is complying with this 

NSPS. The permit should include: 

 Whether the permittee is complying with the primary NSPS 

emission standard (1,100 lb CO2/MWh on a 12-operating-month 

rolling average) or the alternative compliance option 

(between 950 and 1,050 lb CO2/MWh on a 60-operating-month 

rolling average). 

 The BACT emission limit that applies to the EGU (or EGUs) 

at the facility and that does not exceed the selected 

primary or alternative compliance option. 

 Procedures for how the EGU will demonstrate compliance with 

the emission limit, based on the monitoring and 

recordkeeping requirements defined in §60.5355. 

 A requirement that CO2 produced by the EGU (or EGUs) is 

reported under Subpart PP by the owner or operator of the 

EGU. 
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 A requirement that all CO2 that is geologically sequestered 

at the site of the EGU facility is reported under subpart 

RR by the owner or operator of the EGU. 

 A requirement that the captured CO2 sent offsite is 

transferred to an entity that is subject to the 

requirements of Subpart RR. 

We specifically request comment on this basic framework for 

PSD permits that are issued for affected EGU sources that use 

geologic sequestration.

VIII. Rationale for Emission Standards for Natural Gas-fired 

Stationary Combustion Turbines 

A. Best system of emission reduction

The EPA evaluated several different control technology 

configurations as potentially representing the “best system of 

emissions reductions ... adequately demonstrated” (BSER) for new 

natural gas-fired stationary combustion turbines: the use of 

full or partial capture CCS and several types of efficient 

generation without any CCS including high efficiency simple 

cycle aeroderivative turbines and natural gas combined cycle 

(NGCC) technology. We do not consider full or partial capture 

CCS to be BSER because of uncertainties about technical 

feasibility and because of adverse impact on electricity prices 

and the structure of the electric power sector. In addition, we 

Comment [A115]: Is this technical feasibility or 

general feasibility (because of cost) 
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do not consider simple cycle turbines to be BSER because they 

have a higher emission rate and a higher cost than NGCC 

technology. We do find NGCC technology to be the BSER because it 

is technically feasible and relatively inexpensive, its emission 

profile is acceptably low, and it would not adversely affect the 

structure of the electric power sector. 

We note at the outset that currently, virtually all new 

sources in this category are using natural gas combined cycle 

(NGCC) technology. That technology is considered to be the state 

of the art for this source category. Because, in this 

rulemaking, we are considering, and selecting, NGCC as the BSER 

for this category, as a matter of terminology, to avoid 

confusion, we generally refer to the sources as natural gasfired combustion turbines, and not as NGCC sources. 

1. Full and partial CCS 

To determine the BSER for natural-gas-fired stationary 

source combustion turbines, we evaluated full and partial CCS 

against the criteria. We propose to reject CCS technology as the 

BSER because we cannot conclude that it meets several of the key 

criteria. 

First, we are uncertain as to whether full or partial 

capture CCS is technically feasible for this source category. 

Unlike subpart Da affected facilities, where there are several 
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full-scale plants with CCS that are currently under construction 

or in advanced stages of development, the EPA is aware of only 

one demonstration project, which is an approximately 40 MW slip 

stream installation on a 320 MW NGCC unit. Importantly, there 

are some significant differences between natural gas-fired 

combustion turbines and solid fossil fuel-fired EGUs that lead 

us to this conclusion. First, while some of these turbines are 

used to serve baseload power demand, many cycle their operation 

much more frequently than coal-fired power plants. It is unclear 

how part-load operation and frequent startup and shutdown events 

would impact the efficiency and reliability of CCS. We are not 

aware that any of the pilot-scale projects operate in that type 

of mode. None of the larger projects being constructed, or under 

development, are designed to operate in a cycling mode. 

Furthermore, the CO2 concentration in the flue gas of a NGCC is 

much lower (usually approximately 4 volume percent) than the CO2

concentration in the flue gas stream of a typical coal-fired 

plant (which is approximately 16 volume percent for a SCPC or 

CFB unit) or the syngas of an IGCC unit (where it can be as high 

as 60 volume percent).), so the overall amount that can be 

captured for each project is likely lower. 

Moreover, identifying partial or full CCS as the BSER for 

new stationary combustion turbines would have significant 

Comment [A116]: The fact that there is a facility 

in demo phase seems to indicate that it IS technically 

feasible. However, it may not be economical or 

otherwise necessary in the regulatory context to 

pursue such an approach. In any case, this sentence 

does not support the topic sentence of this paragraph. 

Comment [A117]: You mean the one demo 

project, the 40 MW slip stream? Rephrase to note 

one project, if so . 

If there are indeed multiple pilot projects, then this 

would support that it is technically feasible. 

Comment [A118]: Need a conclusion here. 
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adverse effects on national electricity prices, electricity 

supply, and the structure of the power sector. Because virtually 

all new fossil fuel-fired power is projected to use NGCC 

technology, requiring CCS would add significant costs to 

electricity generation across the nation. In addition, requiring 

CCS could lead some operators and developers to forego retiring 

older coal-fired plants and replacing them with new NGCC 

projects, and instead keep the older plants on line longer. 

Identifying CCS and BSER for combustion turbines would likely 

result in higher nationwide electricity prices and could 

adversely affect the supply of electricity, since virtually all 

new fossil fuel-fired power is projected to use NGCC technology. 

We recognize that identifying full or partial CCS would as 

the BSER for this source category would result in significant 

emissions reductions, but at present, we already consider 

natural gas to be a low-GHG-emitting fuel and NGCC to be a lowemitting technology. Although identifying CCS as the BSER would 

promote the development and implementation of emission control 

technology, for the reasons described, the EPA does not believe 

that CCS represents BSER for natural gas combustion turbines at 

this time. 

2. Energy efficient generation technology 

Comment [A119]: Cites? Referencces? 

Comment [A120]: And this would have 

environmental impacts, also. 
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To determine the BSER, the EPA also evaluated the use of 

energy efficient generation technology, including high 

efficiency simple cycle aeroderivative turbines. 

The use of high efficiency simple cycle aeroderivative 

turbines does not provide emission reductions from the current 

state-of-the-art technology – and, in fact, is more expensive 

than the current state-of-the-art technology – nor does it 

develop emission control technology. For these reasons, we do 

not consider it BSER. According to the AEO 2013 emissions rate 

information, this type of source has a CO2 emissions rate of 

1,150 lb CO2/MWh, which is higher than the emission rates of 830 

and 760 lb CO2/MWh for the conventional and advanced NGCC model 

facilities, respectively. 

In the April 2012 proposal, we identified NGCC as the BSER 

for this source category, and proposed a standard of 1,000 

lb/MWh. We stated: 

[A] NGCC facility is the best system of emission 

reduction for new baseload and intermediate load EGUs. 

To establish an appropriate, natural gas-based 

standard, we reviewed the emissions rate of natural 

gas-fired (non-CHP) combined cycle facilities used in 

the power sector that commenced operation between 2006 

and 2010 and that report complete generation data to 

EPA. Based on this analysis, nearly 95% of these 

facilities meet the proposed standards on an annual 

basis. These units represent a wide range of 

geographic locations (with different elevations and 
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ambient temperatures), operational characteristics, 

and sizes.212

The same information supports our current proposal. As 

described above, NGCC has a lower cost of electricity than 

simple cycle turbines at intermediate and high capacity factors. 

In addition, NGCC has an emissions rate that is approximately 25 

percent lower than the most efficient simple cycle facilities. 

Therefore, the use of a heat recovery steam generator in 

combination with a steam turbine to generate additional 

electricity is a cost effective control for intermediate and 

high capacity factor stationary combustion turbines. Therefore, 

BSER for intermediate and high capacity factor stationary 

combustion turbines is the use of modern high efficiency NGCC 

technology. 

B. Determination of the standards of performance 

Multiple commenters on the April 2012 proposal stated the 

proposed standard of 1,000 lb CO2/MWh for combined cycle 

facilities in the April 2012 proposal was too stringent and 

should be increased to a minimum of 1,100 lb CO2/MWh. Commenters 

explained that the increased use of renewable energy for 

electricity generation will require combined cycle facilities to 

startup, shutdown, cycle, and operate at part-load more 

 

212 77 Fed. Reg. at 22,414/1.

Comment [A121]: This section would benefit 

from more explanation for why smaller NGCC units 

meet a particular need. Is it geographic specific? Is 

there a possibility that multiple new smaller units 

would be built instead of one larger unit? 
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frequently than they currently do, and that this more cyclical 

operation necessarily entails a higher emission rate. The 

commenters stated that the recent historical emissions data that 

the EPA relied on for the original proposal does not account for 

these likely operational changes. Additional reasons given 

justifying a higher standard include the deterioration of 

efficiencies over time, the need for flexibility to use 

distillate oil as a backup fuel, the operation of combined cycle 

facilities in simple cycle mode, that combined cycle facilities 

located at high elevations and/or in locations with high ambient 

temperatures are less efficient, and that smaller combined cycle 

facilities are inherently less efficient than larger facilities. 

On the other hand, other commenters stated that the final 

standard should be lower than proposed on grounds that the best 

performing facilities are operating below the original proposed 

standard. Multiple commenters also stated that the EPA should 

evaluate additional CEMS data to determine the appropriate 

standard. 

In light of these comments, we have reviewed the CO2

emissions data from 2007 to 2011 for natural gas-fired (non-CHP) 

combined cycle units that commenced operation on or after 

January 1, 2000 and that reported complete electric generation 

data, including output from the steam turbine, to the EPA. A 
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more detailed description of this emissions data analysis is 

included in a technical support document in the docket for this 

rulemaking. These 307 NGCC units are diverse in location, age, 

capacity, and operating profile. Based on these data, we propose 

to subcategorize the turbines into the same two size-related 

subcategories currently in subpart KKKK for standards of 

performance for the combustion turbine criteria pollutants. 

These subcategories are based whether the design heat input rate 

to the turbine engine is either less than or equal to 850 

MMBtu/h or greater than 850 MMBtu/h. We further propose to 

establish different standards of performance for these two 

subcategories. 

This subcategorization has a basis in differences in 

several types of equipment used in the differently sized units, 

which affect the efficiency of the units. Large-size combustion 

turbines use industrial frame type combustion turbines and may 

use multiple pressure or steam reheat turbines in the heat 

recovery steam generator (HRSG) portion of a combined cycle 

facility. Multiple pressure HRSGs employ two or three steam 

drums that produce steam at multiple pressures. The availability 

of multiple pressure steam allows the use of a more efficient 

multiple pressure steam turbine, compared to a single pressure 

steam turbine. A steam reheat turbine is used to improve the 
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overall efficiency of the generation of electricity. In a steam 

reheat turbine, steam is withdrawn after the high pressure 

section of the turbine and returned to the boiler for additional 

heating. The superheated steam is then returned to the 

intermediate section of the turbine, where it is further 

expanded to create electricity. Although HRSGs with steam reheat 

turbines are more expensive and complex than HRSGs without them, 

steam reheat turbines offer significant reductions in CO2

emission rates. In contrast, small-size combustion turbines 

frequently use aeroderivative turbine engines instead of 

industrial frame design turbines. While there is not a strict 

definition for an aeroderivative turbine, at least parts of 

aeroderivative turbines are derived from aircraft engines. 

Aeroderivative and frame turbines use different combustor 

designs, lubrication oil systems, and bearing designs. While 

aeroderivative turbines are typically more expensive than 

industrial frame turbines, they are generally more compact, 

lighter, are able to start up and shut down more quickly, and 

handle rapid load changes more easily than compared to 

industrial frame turbines. Due to their higher simple cycle 

efficiencies, they have traditionally been used more for peak 

and intermittent purposes rather than base power generation. 

However, combined cycle facilities based on aeroderivative 
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combustion turbines are available. Due to the higher efficiency 

of the simple cycle portion of an aeroderivative turbine based 

combined cycle, the HRSG portion would contribute relatively 

less to the overall efficiency than a HRSG in a frame turbine 

based combined cycle. Therefore, adding a multiple steam 

pressure and/or a reheat steam turbine to the HRSG would be 

relatively more expensive to an aeroderivative turbine based 

combined cycle compared to a frame based combined cycle. 

Consequently, multiple pressure steam and reheat steam turbine 

HRSG are not widely available for aeroderivative turbine based 

combined cycle facilities. In addition, since aeroderivative 

turbine engines have faster start times and change load more 

quickly than frame turbines, aeroderivative turbine based 

combined cycles are more likely to run at part load conditions 

and to potentially bypass the HRSG and run in simple cycle mode 

for short periods of time than industrial frame turbine based 

combined cycle facilities. 

Because of these differences in equipment and inherent 

efficiencies of scale, the smaller capacity NGCC units (850 

MMBtu/h and smaller) available on the market today are less 

efficient than the larger units (larger than 850 MMBtu/h). 

According to the data in the EPA’s Clean Air Markets Division 

database, there is a 7 percent difference in average CO2 emission 
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rate between the small- and large-size units. This relative 

difference is consistent with what would be predicted when 

comparing the efficiency values reported in Gas Turbine World of 

small and large combined cycle designs. Fourteen of the study 

NGCC facilities evaluated using the Clean Air Markets data have 

heat input rates of less than or equal to 850 MMBtu/h, and the 

remaining 293 are above 850 MMBtu/MWh. Two of the small combined 

cycle facilities had a maximum 12-operating-month rolling 

average emissions rate equal to or greater than 1,000 lb CO2/MWh 

and one had an maximum 12-operating-month rolling average 

emissions rate equal to or greater than 1,000 lb CO2/MWh. Twenty 

three of the large turbines had at least one occurrence of a 12-

operating-month rolling average emissions rate greater than or 

equal to 1,000 lb CO2/MWh and forty four had at least one 

occurrence of a 12-operating-month rolling average emissions 

rate greater than or equal to 950 lb CO2/MWh. Therefore, since 

the emission rates of 1,100 lb CO2/MWh and 1,000 lb CO2/MWh 

represent emission rates where over 90 percent of small and 

large existing NGCC are currently operating below respectively, 

these rates are considered BSER for new NGCC in those respective 

subcategories. These values represent the emission rates that a 

modern high efficiency NGCC located in the U.S. would be able to 

maintain over the life of the facility. 

Comment [A122]: Add citation. 
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To further evaluate the impact of the proposed rule we 

reviewed the GHG BACT permits for 8 recently permitted NGCC 

facilities. Of these facilities, 7 are larger than 850 MMBtu/h, 

and 1 is smaller. The 7 larger ones all have emission rates 

below 1,000 lb/MWh, and as low as 880 lb/MWh. The single smaller 

unit, which is 400 MMBtu/h, has a permitted emissions rate of 

1,100 lb CO2/MWh. 

We are requesting comment on a range of 950 to 1,100 lb 

CO2/MWh (430 to 500 kg CO2/MWh) for the large turbine subcategory 

and 1,000 to 1,150 lb CO2/MWh (450 to 520 kg CO2/MWh) for the 

small turbine subcategory. 

IX. Rationale for Other Requirements 

A. Compliance Requirements

The proposed compliance requirements, to the extent 

possible, incorporate monitoring already being performed as part 

of existing part 60 and part 75 requirements. 

We propose to recognize the environmental benefit of 

electricity generated by combined heat and power (CHP) 

facilities to account for the increased end use efficiency 

resulting from avoided transmission and distribution losses. To 

do so, we propose to allow CHP facilities, in calculating their 

emission rate in lb CO2/MWh, deem their MWh to be 5 percent 

higher than actual their MWh, which would lead to a lower 
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emission rate. 

Actual transmission and distribution losses vary from 

location to location, but we propose that this 5 percent of 

actual MWh represents a reasonable average amount for the 

avoided transmission and distribution losses for CHP facilities. 

Note that we propose to limit this 5 percent adjustment to 

facilities for which the useful thermal output is at least 20 

percent of the total output. 

X. Implications for PSD and Title V Programs 

A. Overview

The proposal in this rulemaking would, for the first time, 

regulate GHGs under CAA section 111. Under the EPA’s regulations 

for the CAA PSD preconstruction permit program, and the CAA 

Title V operating permit program, regulation of GHGs under CAA 

section 111 triggers the applicability of PSD. Even so, today’s 

proposal should not require any additional SIP revisions to make 

clear that the Tailoring Rule thresholds – described below - 

continue to apply to the PSD program. 

This issue arises because States with approved PSD programs 

in their state implementation plans (SIPs) implement PSD, and 

most of these States have recently revised their SIPs to 

incorporate the higher thresholds for PSD applicability to GHGs 

that the EPA promulgated under what we call the Tailoring 
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Rule.213 Commenters have queried whether under the EPA’s PSD 

regulations, promulgation of a section 111 standard of 

performance for GHGs would require these states to revise their 

SIPs again to incorporate the Tailoring Rule thresholds again. 

The EPA included an interpretation in the Tailoring Rule 

preamble, which makes clear that the Tailoring Rule thresholds 

continue to apply if and when the EPA promulgates requirements 

under CAA section 111. Even so, in today’s proposal, the EPA is 

including a provision in the CAA section 111 regulations that 

confirms this interpretation. 

However, if a state with an approved PSD SIP program that 

applies to GHGs believes that were the EPA to finalize the 

rulemaking proposed today, the state would be required to revise 

its SIP to make clear that the Tailoring Rule thresholds 

continue to apply, then (i) the EPA encourages the state to do 

so as soon as possible, and (ii) if the State cannot do so 

promptly, the EPA will assess whether to proceed with a separate 

rulemaking action to narrow its approval of that state’s SIP so 

as to assure that for federal purposes, the Tailoring Rule 

 

213 “Prevention of Significant Deterioration and Title V 

Greenhouse Gas Tailoring Rule; Final Rule,” 75 FR 31514 (June 3, 

2010). In the Tailoring Rule, EPA established a process for 

phasing in PSD and Title V applicability to sources based on the 

amount of their GHG emissions, instead of immediately applying 

PSD and title V at the 100 or 250 ton per year or thresholds 

included under the PSD and title V applicability provisions. 
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thresholds will continue to apply as of the effective date of 

the final rule that the EPA is proposing today. 

In the alternative, if the Tailoring Rule thresholds did 

not continue to apply when the EPA promulgates requirements 

under CAA section 111, then the EPA would assess whether to 

proceed with a separate rulemaking action to narrow its approval 

of all of the State’s approved SIP PSD programs to assure that 

for federal purposes, the Tailoring Rule thresholds will 

continue to apply as of the effective date the final rule that 

EPA is proposing today. 

As discussed below, in the case of title V, today’s 

rulemaking does not have implications for the Tailoring Rule 

thresholds established with respect to sources subject to title 

V requirements. 

B. Implications for PSD program

Under the PSD program in part C of title I of the CAA, in 

areas that are classified as attainment or unclassifiable for 

NAAQS pollutants, a new or modified source that emits any air 

pollutant subject to regulation at or above specified thresholds 

is required to obtain a preconstruction permit. This permit 

assures that the source meets specified requirements, including 

application of best available control technology. States 

authorized for the PSD program may issue PSD permits. If a state 

Comment [A123]: Consider moving this text out 

of the Overview section and into the Implications 

Section. It is more informative to provide this after 

the background information. 
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is not authorized, then the EPA issues the PSD permits. 

 Regulation of GHG emissions in the Light Duty Vehicle Rule 

(75 FR 25324) triggered applicability of stationary sources to 

regulations for GHGs under the PSD and title V provisions of the 

CAA. Hence, on June 3, 2010 (75 FR 31514), the EPA issued the 

“Tailoring Rule,” which establishes thresholds for GHG emissions 

in order to define and limit when new and modified industrial 

facilities must have permits under the PSD and title V programs. 

The rule addresses emissions of six GHGs: CO2, CH4, N2O, HFCs, 

PFCs and SF6. On January 2, 2011, large industrial sources, 

including power plants, became subject to permitting 

requirements for their GHG emissions if they were already 

required to obtain PSD or title V permits due to emissions of 

other (non-GHG) air pollutants. 

Commenters have queried whether, because of the way that 

the EPA’s PSD regulations are written, promulgating the rule we 

propose today may raise questions as to whether the EPA must 

revise its PSD regulations –- and, by the same token, whether 

states must revise their SIPs –- to assure that the Tailoring 

Rule thresholds will continue to apply to sources subject to 

PSD. That is, under the EPA’s regulations, PSD applies to a 

“major stationary source” that undertakes construction and to a 

“major modification.” 40 CFR 51.166(a)(7)(i) and (iii). A “major 
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modification” is defined as “any physical change in or change in 

the method of operation of a major stationary source that would 

result in a significant emissions increase . . . and a 

significant net emissions increase . . . .” Thus, for present 

purposes, the key component of these applicability provisions is 

that PSD applies to a “major stationary source.” 

The EPA’s regulations define the term “major stationary 

source” as a “stationary source of air pollutants which emits, 

or has the potential to emit, 100 [or, depending on the source 

category, 250] tons per year or more of any regulated NSR 

pollutant.” 40 CFR 51.166(b)(1)(i)(a). The EPA’s regulations go 

on to define “regulated NSR pollutant” as follows, in relevant 

part: 

(b)(49) Regulated NSR pollutant, for purposes of 

this section, means the following: 

(i) Any pollutant for which a national ambient 

air quality standard has been promulgated and any 

pollutant identified under this paragraph 

(b)(49)(i) as a constituent or precursor to such 

pollutant.... 

(ii) Any pollutant that is subject to any 

standard promulgated under section 111 of the 

Act; 

(iii) Any Class I or II substance subject to a 

standard promulgated under or established by 

title VI of the Act; 
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(iv) Any pollutant that otherwise is subject to 

regulation under the Act as defined in paragraph 

(b)(48) of this section.... 

40 CFR 51.166(b)(49). Thus, the PSD regulations contain a 

separate PSD trigger for pollutants regulated under the NSPS, 40 

CFR 51.166(b)(49)(ii) (the “NSPS trigger provision”), so that as 

soon as the EPA promulgates the first NSPS for a particular air 

pollutant, as we are doing in this rulemaking with respect to 

the GHG air pollutant, then PSD is triggered for that air 

pollutant. 

The Tailoring Rule, on the face of its regulatory provisions, 

incorporated the revised thresholds it promulgated into only the 

fourth prong (“[a]ny pollutant that otherwise is subject to 

regulation under the Act”), and not the second prong (“[a]ny 

pollutant that is subject to any standard promulgated under 

section 111 of the Act”). For this reason, a question may arise 

as to whether the Tailoring Rule thresholds apply to the PSD 

requirement as triggered by the NSPS that the EPA is 

promulgating in this rulemaking. 

However, although the Tailoring Rule thresholds on their face 

apply to only the term, “subject to regulation” in the 

definition of “regulated NSR pollutant,” the EPA stated in the 

Tailoring Rule preamble that the thresholds should be 

interpreted to apply to other terms in the definition of “major 
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stationary source” and in the statutory provision, “major 

emitting facility.” Specifically, the EPA stated: 

3. Other Mechanisms 

As just described, we selected the “subject to 

regulation” mechanism because it most readily 

accommodated the needs of States to expeditiously 

revise – through interpretation or otherwise -- their 

state rules. Even so, it is important to recognize 

that this mechanism has the same substantive effect as 

the mechanism we considered in the proposed rule, 

which was revising numerical thresholds in the 

definitions of major stationary source and major 

modification. Most importantly, although we are 

codifying the “subject to regulation” mechanism, that 

approach is driven by the needs of the states, and our 

action in this rulemaking should be interpreted to 

rely on any of several legal mechanisms to accomplish 

this result. Thus, our action in this rule should be 

understood as revising the meaning of several terms in 

these definitions, including: (1) the numerical 

thresholds, as we proposed; (2) the term, “any 

source,” which some commenters identified as the most 

relevant term for purposes of our proposal; (3) the 

term, “any air pollutant; or (4) the term, “subject to 

regulation.” The specific choice of which of these 

constitutes the nominal mechanism does not have a 

substantive legal effect because each mechanism 

involves one or another of the components of the terms 

“major stationary source” - which embodies the 

statutory term, “major emitting facility” -- and 

“major modification,” which embodies the statutory 

term, “modification,” and it is those statutory and 

regulatory terms that we are defining to exclude the 

indicated GHG-emitting sources. [Footnote] 

[Footnote: We also think that this approach 

better clarifies our long standing practice of 

interpreting open-ended SIP regulations to 

automatically adjust for changes in the regulatory 

status of an air pollutant, because it appropriately 

assures that the Tailoring Rule applies to both the 

definition of “major stationary source” and “regulated 

NSR pollutant.” ] 
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75 FR 31582. 

Thus, according to the preamble of the final Tailoring 

Rule, the definition of “major stationary source” itself already 

incorporates the Tailoring Rule thresholds, and not just through 

one component (the “subject to regulation” prong of the term 

“regulated NSR pollutant”) of that definition. For this reason, 

it is the EPA’s position that the Tailoring Rule thresholds 

continue to apply even when the EPA promulgates the first NSPS 

for GHGs (which, as noted above, triggers the PSD requirement 

under the NSPS trigger provision in the definition of “regulated 

NSR pollutant”).214 To clarify and confirm that the Tailoring 

Rule thresholds apply to the section 111 prong of the definition 

of regulated NSR pollutant, in this proposed rulemaking, the EPA 

is proposing to revise the NSPS regulations, although not the 

PSD regulations, to explicitly make clear that the NSPS trigger 

 

214 This position reads the regulations to be consistent with the 

CAA PSD provisions themselves. Under those provisions, PSD 

applies to any “major emitting facility,” which is defined to 

mean stationary sources that emit or have the potential to emit 

“any air pollutant” at either 100 or 250 tons per year, 

depending on the source category. CAA section 165(a), 169(1). 

EPA has long interpreted these provisions to apply PSD to a 

stationary source that emits the threshold amounts of any air 

pollutant subject to regulation. See Tailoring Rule, 75 FR 

31579. Under these provisions, at present, PSD is already 

applicable to GHGs because GHGs are already subject to 

regulation, and regulating GHGs under CAA section 111 does not 

any additional type of PSD trigger. 

Comment [A124]: The last clause of this FN 

seems to be missing a word. 

Formatted: Highlight
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provision in the PSD regulations incorporate the Tailoring Rule 

thresholds. The rationale for the Tailoring Rule thresholds 

remains equally applicable in this context.

As a result, the EPA believes that states that incorporated 

the Tailoring Rule thresholds into their SIPs may take the 

position that they also incorporated the EPA’s interpretation in 

the preamble that the thresholds apply to the definition “major 

stationary source.” 

The EPA requests that all States with approved SIP PSD 

programs that apply to GHGs indicate during the comment period 

on this rule whether they can interpret their SIPs already to 

apply the Tailoring Rule thresholds to the NSPS prong or whether 

they must revise their SIPs. For any State that says it must 

revise its SIP (or that does not respond), the EPA will assess 

whether to propose a rule that is comparable to the SIP PSD 

Narrowing Rule shortly after the close of the comment period, 

and may finalize that rule at the same time that it finalizes 

this NSPS rule. 

C. Implications for title V program

Under the title V program, a source that emits any air 

pollutant subject to regulation at or above specified thresholds 

(along with certain other sources) is required to obtain an 

operating permit. This permit includes all of the CAA 
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requirements applicable to the source. These permits are 

generally issued through EPA-approved State title V programs. 

As the EPA explained in the Tailoring Rule preamble, title 

V applies to a “major source,” CAA section 502(a), which is 

defined to include, among other things, certain sources, 

including any “major stationary source,” CAA section 501(2)(B), 

which, in turn, is defined to include a stationary source of 

“any air pollutant” at or above 100 tpy. CAA section 302(j). The 

EPA’s regulations under title V define the term “major source,” 

and in the Tailoring Rule, the EPA revised that definition to 

make clear that the term is limited to stationary sources that 

emit any air pollutant “subject to regulation.” The EPA 

incorporated the Tailoring Rule threshold within the definition 

of “subject to regulation.” The EPA described its action as 

follows in the preamble to the Tailoring Rule: 

Thus, EPA is adding the phrase “subject to 

regulation” to the definition of “major source” under 

40 CFR 70.2 and 71.2. EPA is also adding to these 

regulations a definition of “subject to regulation.” 

Under the part 70 and part 71 regulatory changes 

adopted, the term “subject to regulation,” for 

purposes of the definition of “major source,” has two 

components. The first component codifies the general 

approach EPA recently articulated in the 

“Reconsideration of Interpretation of Regulations That 

Determine Pollutants Covered by Clean Air Act 

Permitting.” 75 FR 17704. Under this first component, 

a pollutant “subject to regulation” is defined to mean 

a pollutant subject to either a provision in the CAA 

or regulation adopted by EPA under the CAA that 

requires actual control of emissions of that pollutant 
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and that has taken effect under the CAA. See id. at 

17022-23; Wegman Memorandum at 4-5. To address 

tailoring for GHGs, EPA includes a second component of 

the definition of “subject to regulation,” specifying 

that GHGs are not subject to regulation for purposes 

of defining a major source, unless as of July 1, 2011, 

the emissions of GHGs are from a source emitting or 

having the potential to emit 100,000 tpy of GHGs on a 

CO2e basis. 

75 Fed. Reg. at 31,583. 

Unlike the PSD regulations described above, the title V 

definition of “major source”, as revised by the Tailoring Rule, 

does not on its face distinguish among types of regulatory 

triggers for title V. Because title V has already been triggered 

for GHG-emitting sources, the promulgation of CAA section 111 

requirements has no further impact on title V applicability 

requirements for major sources of GHGs. Accordingly, today’s 

rulemaking has no title V implications with respect to the 

Tailoring Rule threshold. Of course, unless exempted by the 

Administrator through regulation under CAA section 502(a), 

sources subject to a NSPS are required to apply for, and operate 

pursuant to, a title V permit that assures compliance with all 

applicable CAA requirements for the source, including any GHGrelated requirements. We have concluded that this rule will not 

affect non-major sources and there is no need to consider 

whether to exempt non-major sources. 

Note that we propose to move the definition of “Greenhouse 
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gases” currently within the definitions of “Subject to 

regulation” in 40 CFR 70.2 and 71.2 to a definition within 70.2 

and 71.2 to promote clarity in the regulations. 

D. Implications for title V fees requirements for GHGs

The issuance of the final EGU GHG NSPS will trigger certain 

requirements related to title V fees for GHG emissions under 40 

CFR part 70 and part 71. States (including approved local and 

tribal permitting authorities) will be required to include GHG 

emissions in determining whether they collect adequate fees, if 

the state relies on the “presumptive minimum” approach to 

demonstrating fee adequacy. In addition, sources subject to 

federal permitting under part 71 will be required to include GHG 

emissions in calculating their annual permit fee.215 The EPA is 

proposing changes to the title V rules to limit the impact of 

the requirements that would otherwise occur under the existing 

rules, provide flexibility to the states to ensure sufficient 

funding for their programs, and to ensure that the requirements 

are consistent with the Clean Air Act. 

These requirements would be triggered because the 

regulation of GHGs under section 111 for the first time through 

 

215 Also, we understand several states may have fee requirements 

that are structured with similar definitions that would result 

in GHGs being added to the list of air pollutants that are 

subject to title V fees. 
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the issuance of the EGU GHG NSPS would make GHGs a “regulated 

air pollutant,” as defined under 40 CFR parts 70 and 71, a 

“regulated pollutant (for presumptive fee calculation)” as 

defined under part 70 and a “regulated pollutant (for fee 

calculation)” as defined under part 71. 

Under the current part 70, regulation of GHGs under section 

111 through the issuance of any NSPS would result in GHGs being 

added to the list of air pollutants used in “presumptive 

minimum” fee calculations. Also, in EPA’s part 71 permit 

program, and possibly in certain state part 70 programs, 

issuance of a NSPS standard would result in GHGs being added to 

the list of air pollutants that are subject to fee payment by 

sources. This effect of adding GHGs to certain title V fee 

requirements was not discussed in the previous proposal for the 

EGU GHG NSPS; however, several public comments were raised on 

this issue, and a number of related issues, during the public 

comment period on the previous proposal for the EGU GHG NSPS. 

In this re-proposal of the EGU GHG NSPS, we discuss this 

issue for GHGs related to title V fees and propose rule 

amendments that will enable permitting authorities to collect 

fees as needed to support their programs, to avoid excessive and 

unnecessary fees. We also respond to and clarify some related 

issues raised by commenters on the previous proposal. 
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In summary, we are proposing to exempt GHGs from the 

presumptive fee calculation, yet account for the costs of GHG 

permitting program costs through a cost adjustment to ensure 

that fees will be collected that are sufficient to cover the 

program costs. We are also proposing that permitting agencies 

that do not use the presumptive fee approach can continue to 

demonstrate that their fee structures are adequate to implement 

their title V programs. 

Prior to explaining our proposal in more detail, the 

following discussion provides background on the fee requirements 

of the title V rules, what those fees cover in terms of 

agencies’ program implementation, what additional activities 

agencies might be expected to have to undertake as a result of 

GHGs becoming “regulated pollutants” under the NSPS, what the 

GHG Tailoring Rule said about title V fees, background on title 

V fees in the context of the previous proposal for the EGU GHG 

NSPS, and existing limitations on the collection of GHG fees. 

1. Background 

a. The title V rules

Title V is implemented through 40 CFR parts 70 and 71. 

Part 70 defines the minimum requirements for state, local and 

tribal (state) agencies to develop, implement and enforce a 

title V operating permit program; these programs are developed 
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by the state and the state submits a program to EPA for a review 

of consistency with part 70. There are about 112 approved part 

70 programs in effect, with about 15,000 part 70 permits 

currently in effect. (See Appendix A of 40 CFR part 70 for the 

approval status of each state program). Part 71 is a federal 

permit program run by the EPA, primarily where there is no part 

70 program in effect (e.g., in Indian country, the federal OCS 

and for offshore LNG terminals).216 There are about 100 part 71 

permits currently in effect (most are in Indian country). 

b. The fee requirements of title V

Section 502(b)(3)(A) of the Act requires owners or 

operators of all sources subject to permitting to “pay an annual 

fee, or the equivalent over some other period, sufficient to 

cover all reasonable (direct and indirect) costs required to 

develop and administer the permit program.” Section 502(b)(3)(B) 

of the Act generally sets forth the methods for determining 

whether a permitting authority is collecting sufficient fees in 

total to cover the costs of the program. First, under the 

“presumptive minimum” approach set forth in section 

 

216 In some circumstances, EPA may delegate authority for part 71 

permitting to another permitting agency, such as a tribal agency 

or a state. The EPA has entered into delegation agreements for 

certain part 71 permitting activities with at least one tribal 

agency. There are currently no states that do not have an 

approved part 70 program; thus, there is no need for EPA to 

delegate part 71 permitting authority to any state at this time.

Comment [A125]: Spell out 
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502(b)(3)(B)(i), a state can satisfy the requirement by showing 

that “the program will result in the collection, in the 

aggregate, from all sources subject to [the program] of an 

amount not less than $25 per ton of each regulated pollutant, or 

such other amount as the Administrator may determine adequately 

reflects the reasonable costs of the permit program.” The 

statute further provides that emissions in excess of 4,000 tpy 

for any one pollutant need not be included in the calculation, 

and that the initial fee rate ($25 per ton) shall be adjusted 

for inflation217. See section 502(b)(3)(B)(iii)-(v). Also, 

section 502(b)(3)(B)(ii) of the Act sets forth a definition of 

“regulated pollutant” for purposes of the presumptive fee 

calculation that includes, in part, each pollutant regulated 

under section 111 of the Act, such as any pollutants regulated 

under any NSPS, which would make GHG a “regulated pollutant” 

based on our proposal for the EGU GHG NSPS. Each of the title V 

rules that implement title V contains a definition of “regulated 

air pollutant”218 (at 40 CFR 70.2 and 71.2) that tracks the Act 

 

217 The current corresponding part 70 fee rate, adjusted for 

inflation, is approximately $47 per ton. 

218 The definition reads in relevant part: “Regulated air 

pollutant means the following: (1) Nitrogen oxides or any 

volatile organic compounds; (2) Any pollutant for which a 

national ambient air quality standard has been promulgated; (3) 

Any pollutant that is subject to any standard promulgated under 

section 111 of the Act; (4) Any Class I or II substance subject 
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definition of “regulated pollutant.” The “regulated air 

pollutant" definition is used in the regulatory text for 

applicable requirements and other purposes and it is relevant 

for fee purposes because it is cross-referenced as the starting 

point for two fee-related definitions: “regulated pollutant (for 

presumptive fee calculation)219” in 40 CFR 70.2 and “regulated 

pollutant (for fee calculation)220” in 40 CFR 71.2. 

Alternatively, if a state does not wish to show it collects 

an amount of fees at least equal to the presumptive minimum 

amount, section 502(b)(3)(B)(iv) provides that a program may be 

approved if the state demonstrates that it collects sufficient 

fees to cover the costs of the program, even if that amount is 

below the presumptive minimum. 

 

to a standard promulgated under or established by title VI of 

the Act; or (5) Any pollutant subject to a standard promulgated 

under section 112 or other requirements established under 

section 112 of the Act, including sections 112(g), (j), and (r) 

of the Act . . .” 

219 40 CFR 70.2 defines regulated pollutant (for presumptive fee 

calculation) to mean: “any ‘regulated air pollutant’ except the 

following: (1) Carbon monoxide; (2) Any pollutant that is a 

regulated air pollutant solely because it is a Class I or II 

substance to a standard promulgated under or established by 

title VI of the Act; or (3) Any pollutant that is a regulated 

air pollutant solely because it is subject to a standard or 

regulation under section 112(r) of the Act.” 

220 40 CFR 71.2 defines regulated pollutant (for fee calculation) 

the same as regulated pollutant (for presumptive fee calculation 

in 40 CFR 70.2.
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The presumptive fee approach of the statute is reflected in 

the part 70 regulations for those states that wish to use it for 

fee adequacy purposes. In addition, for the federal part 71 

permitting program, which the EPA implements directly, the EPA 

has adopted rules to ensure that it collects adequate fees, 

consistent with the statute. These Act requirements for fees are 

reflected in 40 CFR 70.9 and 71.9, respectively. 

Although the Clean Air Act and part 70 require that a title 

V permit program must collect sufficient fees to cover the costs 

of the program, neither the Act nor part 70 specifies the 

details of how those fees must be charged to particular sources 

in their fee schedules. The part 70 regulations specifically 

provide, at 40 CFR 70.9(b)(3), that a “state program’s fee 

schedule may include emission fees, application fees, service 

fees or other types of fees, or any combination thereof.” Many 

states use emission fees and other types of fees in combination 

in their fee schedules and we understand that some state fee 

schedules are structured such that they would result in GHG fees 

being required when GHGs are regulated under any NSPS. For 

example, states may have chosen for convenience sake to use the 

“regulated pollutant (for presumptive fee calculation)” 

definition of part 70, or a similar state definition, to 

identify the pollutants subject to fees as part of their fee 
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schedule. For part 71, the EPA chose to promulgate an emissionsbased fee schedule that uses the definition of “regulated 

pollutants (for fee calculation)” to identify the pollutants 

subject to fees, and thus, part 71 is structured such that GHG 

fees would be required when GHGs are regulated under any NSPS. 

State fee schedules charge emissions-based fees that range 

from about $15 to $100 or more per ton for each air pollutant 

for which they charge a fee, while part 71 charges about $48 per 

ton221, effective for calendar year 2013, for each of the 

“regulated pollutants (for fee calculation).” See 40 CFR 

71.9(c)(1). Most part 70 and part 71 programs require sources to 

pay the fees on an annual basis, initially with the submittal of 

its permit application, and thereafter, on the anniversary of 

application submittal. See 40 CFR 70.9(a), 71.9(e). 

Section 502(b)(3)(A) of the CAA broadly requires permit 

fees “sufficient to cover all reasonable (direct and indirect) 

costs required to develop and administer the permit program” 

including the reasonable costs of: “(i) reviewing and acting 

upon any application for such a permit, (ii) implementing and 

 

221 Note that the part 71 fee rate and the part 70 presumptive 

fee rate are slightly different because the part 71 rate was set 

based on an analysis that showed that the EPA needed slightly 

more than the presumptive minimum to collect sufficient revenue 

to fund the program. 
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enforcing the terms and conditions of any such permit (not 

including any court costs or other costs associated with any 

enforcement action), (iii) emissions and ambient monitoring, 

(iv) preparing generally applicable regulations, or guidance, 

(v) modeling, analyses, and demonstrations, and (vi) preparing 

inventories and tracking emissions.” These statutory 

requirements were incorporated into the regulations at 40 CFR 

70.9(b)(1) and 71.9(b), EPA has provided detailed guidance on 

EPA’s interpretation of this list of activities in several 

memoranda,222 and these activities have been considered in the 

context of the ICR development and renewal process for part 70 

and 71. 

c. How EPA Addressed Title V Fees in the Tailoring Rule 

The GHG Tailoring Rule concerned when sources are required 

to obtain permits under prevention of significant deterioration 

(PSD) and title V due to emissions of GHGs. (See Prevention of 

Significant Deterioration and Title V Greenhouse Tailoring Rule; 

Final Rule [the Tailoring Rule]; 75 FR 31514, June 3, 2010.) 

GHGs became subject to regulation as a result of the Light Duty 

Vehicle Rule (75 FR 25,234, May 7, 2010), and the Tailoring Rule 

 

222 For example, see “Reissuance of Guidance on Agency Review of State Fee Schedules for 

Operating Permits Programs Under Title V”; from John S. Sietz, Director, Office of Air Quality 

Planning and standards, to Air Division Directors, Regions I-X; August 4, 1993; available at 

http://www.epa.gov/region07/air/title5/t5memos/fees.pdf. 
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established emissions thresholds for purposes of PSD and title 

V. Neither the Light Duty Vehicle Rule nor the Tailoring Rule 

made any changes that would cause GHGs to meet the definition of 

“regulated air pollutant,” or related fee definitions in the 

title V regulations. EPA has promulgated no other standards that 

would trigger fee requirements for GHGs in title V programs. 

The GHG Tailoring Rule addressed the possible need for 

states and the EPA to charge fees for GHG emissions based on the 

burdens imposed under the Tailoring Rule for states to 

incorporate GHGs into permits or to issue permits to sources 

based on GHG emissions. We did not revise the part 70 rules to 

require fees for GHGs, although we did clarify that states have 

the option of charging fees to recover the costs of permitting 

related to GHGs. Also, we did not revise part 71 to require GHG 

fees, and we stated that we would review the need for additional 

fees to cover program costs for GHGs over time. (See 75 FR 31526 

and 31584.) We retained this approach in last year’s Step 3 

Tailoring Rule. (See Prevention of Significant Deterioration and 

Title V Greenhouse Tailoring Rule Step 3, GHG Plantwide 

Applicability Limitations and GHG Synthetic Minor Limitations, 

(Step 3 of the Tailoring Rule), 77 FR 41051, July 12, 2012). 

d. Title V fees in the previous EGU GHG NSPS proposal
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 The previous EGU GHG NSPS proposal did not discuss any 

title V fee issues related to regulating GHGs under a section 

111 standard; however, several public commenters (two state 

agencies and one industry group) raised several concerns or 

asked for clarification on a number of issues related to title V 

fees during the public comment period. Two of these commenters 

requested clarification as to whether the issuance of the EGU 

GHG NSPS would make either GHGs or CO2 subject to regulation such 

that title V fee requirements would be triggered for either of 

these pollutants. One commenter requested clarification on 

whether fees are required for “regulated NSR pollutants,” such 

as GHG. One commenter questioned whether the rationale of the 

Tailoring Rule for deferring fees for GHGs would also apply to 

the EGU GHG NSPS. Finally, one commenter asked us to clarify if 

a state could refrain from charging a fee for CO2 (based on the 

issuance of the EGU GHG NSPS) if the state otherwise generates a 

fee sufficient to meet the “program support requirements” of 

title V. Note that we address the substance of several of these 

comments related to title V fees in section B of this portion of 

the proposal. 

e. Unique Characteristics of GHGs relative to Fees

 There are a number of provisions in part 70 and part 71 and 

characteristics of GHGs that are relevant to any discussion 
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related to charging fee for GHGs. First, it should be noted that 

GHG are emitted in extremely high quantities relative to other 

air pollutants, such as the criteria pollutants, which are 

typically emitted by combustion sources that also emit GHGs. A 

review of emission factors in EPA’s AP-42 shows that GHGs are 

typically emitted in quantities as much as one thousand or more 

times higher than CO or NOX and many other pollutants as a 

product of combustion for a given mass of fuel223. Thus, we 

expect that charging fees for GHGs at the same rate (in dollars 

per ton) as other regulated air pollutants would lead to fee 

revenue that would be excessive, far beyond the reasonable costs 

of the program. Even though most part 70 and 71 programs cap 

total fees at 4,000 tons per air pollutant per year224 we note 

that the total GHG fee for a particular source under the current 

part 71 rule could still be significant, up to about $194,000 

per year for GHGs alone, if GHGs are charged at the same rate as 

for other “regulated pollutants (for fee calculation).”225 

 

223 See AP-42, Compilation of Air Pollution Emission Factors, 

Volume I, Stationary and Area Sources, Fifth Edition. For 

example, for external combustion of bituminous and subbituminous 

coals, see table 1.1-3 for NOx and CO emission factors and table 

1.1-20 for CO2 emissions factors. 224 Consistent with the option afforded states at 40 CFR 

70.9(b)(2)(ii)(B) and the EPA’s fee schedule at 40 CFR 

71.9(c)(5).

225 Note that most sources that emit GHGs, particularly major 

sources of GHG, also emit other regulated air pollutants subject 
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Second, unlike other pollutants, GHGs can be estimated in two 

ways: by mass or by CO2 equivalent (CO2e). While the title V 

permitting threshold for the Tailoring Rule was established at 

100,000 CO2e and 100 tpy mass, the fee provisions of part 70 and 

71, and we believe the fee provisions of the majority, if not 

all, state programs, charge fees on a mass (per ton), rather 

than on a CO2e226, basis. See 40 CFR 70.9(b)(2)(i) and 40 CFR 

71.9(c)(1). 

2. Response to comments on fees from the previous EGU GHG NSPS 

proposal 

In response to concerns raised by commenters, and because 

response to certain of these issues will help to provide a 

better proposal, we respond to several of these comments at this 

time. In response to the question as to whether CO2 or GHGs 

would be regulated by the EGU GHG NSPS, we clarify that GHG 

would be regulated under section 111 of the Act and that this 

does not affect the applicability thresholds previously 

 

to fees; thus, they would pay significant title V fees even if a 

fee for GHGs is not charged. 

226 The term “tpy CO2 equivalent emissions” (or “CO2e”) is defined 

within the definition of “subject to regulation” in 40 CFR 70.2 

and 71.2. The definitions read, in relevant part, “[CO2e] shall 

represent an amount of GHGs emitted, and shall be computed by 

multiplying the mass amount of emissions (tpy), for each of the 

six greenhouse gases in the pollutant GHGs, by the gas's 

associated global warming potential published at Table A-1 to 

subpart A of part 98 of this chapter—Global Warming Potentials, 

and summing the resultant value for each to compute a tpy CO2e. 
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established for PSD and title V in the Tailoring Rule. First, 

the EPA considers the pollutant being regulated by the NSPS for 

the purposes of PSD and by title V to be GHG, rather than CO2. 

Thus, under this interpretation, this NSPS has not caused CO2 to 

be treated as a “regulated air pollutant” under the third prong 

of the definition of “regulated air pollutant” contained in 40 

CFR 70.2 and 71.2, which includes “[a]ny pollutant that is 

subject to any standard promulgated under section 111 of the 

Act,” because it causes GHG to be the “regulated air pollutant.” 

Second, although EPA’s PSD regulations provide that regulation 

of GHGs under CAA section 111 triggers PSD applicability, the 

Tailoring Rule thresholds for GHG continue to apply for major 

source applicability for both the PSD and Title V permitting 

programs. We have clarified these points further in a memorandum 

we have added to the docket for this rulemaking (“PSD Threshold 

Memorandum,” dated May 8, 2012). (See document number EPA-HQOAQPS-2011-0660-7602). 

In response to the comment inquiring whether the rationale 

of the Tailoring Rule remains relevant for deferring action on 

fees, we are proposing several revisions to the part 70 and part 

71 regulations in response to the proposed regulation of GHGs 

under section 111, while retaining the general approach that we 

described in the Tailoring Rule. At the time of the promulgation 
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of the Tailoring Rule, there were no section 111 standards (or 

other standards) that had been promulgated that would have 

resulted in title V fee requirements being triggered for GHGs. 

Thus the rationale we use now is necessarily different that the 

rationale we used for the Tailoring Rule fee discussion. If the 

commenter is referring to the requests of certain state agencies 

in their comments on the Tailoring Rule for the EPA to set a 

presumptive fee of GHGs, we are responding to that request in 

this proposal by proposing to set a presumptive fee cost 

adjustment. If the commenter is referring to the fee flexibility 

afforded by 40 CFR 70.9(b)(3), we respond that we are not 

proposing to revise that regulatory provision. A state commenter 

generally asked us if it could not refrain from requiring a fee 

for CO2 (or GHG) if it could show that they can otherwise 

generate a fee sufficient to meet the “program support 

requirements” of title V. The response to this comment is yes, 

based on the following analysis. Title V requires permitting 

authorities to collect fees from sources that are ‘‘sufficient 

to cover all reasonable (direct and indirect) costs required to 

develop and administer [title V] programs.”227 States have 

adopted various fee schedules to meet this requirement. 40 CFR 

 

227 The fee provisions are set forth in CAA section 502(b)(3) and 

in our regulations at 40 CFR 70.9 and 71.9. 
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70.9(b)(3) allows a State program's fee schedule to include 

emissions fees, application fees, service-based fees or other 

types of fees, or any combination thereof, to meet the 

requirements of the collection and retention of revenues 

sufficient to cover the permit program costs. Further, states 

are not required to calculate fees on any particular basis or in 

the same manner for all part 70 sources or for all regulated air 

pollutants, provided that they collect a total amount of fees 

sufficient to meet the program support requirements. This 

flexibility is also true for states that use the presumptive 

minimum approach to demonstrate they would collect sufficient 

fees to fund the program. In the final Tailoring Rule (75 Fed. 

Reg. 31584, June 3, 2010), we did not change our fee regulations 

to require title V fees for GHGs or require new fee 

demonstrations from states related to permitting GHGs, and we 

have retained the same policies for the purposes of the recent 

Step 3 rule (77 Fed. Reg. 41051, July 12, 2012). In the final 

Tailoring Rule, we recommended that each state, local or tribal 

program review its resource needs for GHGs and determine if the 

existing fee approaches would be adequate. If those approaches 

were not adequate, we suggested that they should be proactive in 

raising fees to cover the direct and indirect costs of the 

program or develop other alternative approaches to meet the 
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shortfall. Therefore, we agree with the commenter that 

consistent with 40 CFR 70.9(b)(3), if a state generates fees 

“sufficient to meet the program support requirements,” without 

charging fees based on GHG emissions, then a fee does not have 

to be charged specifically for GHGs.228 Thus, this proposal does 

not seek to revise fee schedule flexibility for states and 

instead focuses on revising the presumptive minimum fee 

provisions under part 70 to more appropriately account for GHG 

program costs. This notice does not propose any new requirements 

for states that do not use the presumptive approach to establish 

adequacy of fees. 

3. Today’s proposal to address GHGs in title V fees

In this part of the preamble we explain and solicit comment 

on options to address the title V fee issues raised by the 

proposed regulation of GHGs under this NSPS. In sum, we propose 

to exempt GHGs from the presumptive fee calculation, yet account 

for the costs of GHG permitting through a cost adjustment to 

ensure that fees will be collected that are sufficient to cover 

the program costs. We request comment on these proposals, 

particularly from state, local, and tribal permitting agencies, 

 

228 Conversely, where a state cannot show that sufficient fees 

are being collected, the state would need to modify its fee 

schedule (which could, but need not, involve charging fees for 

GHG emissions). 
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and particularly with respect to which approach would be most 

appropriate, feasible, and workable and result in fees that 

would be adequate to cover the direct and indirect costs of 

permitting GHGs. We also invite comments on ways to improve 

this proposal and/or address this issue in other ways consistent 

with the same principles, concerns, and statutory authority that 

we have described for this proposal. 

a. Exemption of GHGs from presumptive fee calculation

 For the reasons discussed earlier in this proposal, we 

propose to exempt GHGs from the definition of “regulated 

pollutant (for presumptive fee calculation)” in 40 CFR 70.2 in 

order to exclude GHGs from being subject to the statutory fee 

rate set for the presumptive minimum fee calculation of 40 CFR 

70.9(b)(2)(i). Pursuant to the authority of section 

502(b)(3)(B)(i), we are proposing to determine that utilizing 

the statutory fee rate for GHGs would be inappropriate because 

it would result in excessive fees, far above the reasonable 

costs of a program. Thus,nd we are proposing a significantly 

smaller cost adjustment for GHGs to reflect the program costs 

related to GHGs. 

 We have estimated the cost of permitting GHGs associated 

with the Tailoring Rule thresholds in several documents, in an 

economic analysis performed for the Tailoring Rule and in 
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several documents related to Information Collection Request 

(ICR) requirements for part 70 and 71, and we believe these 

analyses provide a basis for estimating the costs related to GHG 

permitting for the typical permitting authority. Thus, we 

propose to revise 40 CFR 70.9(b)(2)(i) to add a GHG cost 

adjustment to account for the GHG permitting program costs. 

b. Addition of a GHG cost adjustment to the presumptive minimum 

fee calculation 

 We propose to revise the presumptive minimum fee provisions 

of part 70 to add a GHG cost adjustment to account for the 

typical GHG permitting program costs that may not already be 

covered by the existing presumptive minimum fee provisions of 

parts 70 and 71. The current presumptive minimum fee provisions 

of the title V rules implements the statutory mandate to collect 

fees that are sufficient to cover the direct and indirect GHG 

program costs. Since we are not proposing to charge fees for 

GHGs at the statutory rate ($25 per ton, adjusted for inflation) 

due to concerns raised by permitting authorities and others 

about this resulting in excessive fees, we may need an 

alternative presumptive minimum fee to recover any costs related 

to GHGs that would not otherwise be covered by the presumptive 

minimum fee that is calculated based on emissions of regulated 

air pollutants, excluding GHGs. We estimated certain incremental 
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GHG program costs that would not be covered under the context of 

the Tailoring Rule, but we did not revise our permit rule to 

reflect those costs at that time. We are aware that the EGU NSPS 

may further increase permitting authority costs above the levels 

that would be covered by presumptive minimum fee provisions that 

exclude GHGs, and we are concerned that accounting for GHGs 

using the statutory rate would result in excessive calculation 

of costs. Thus, to address these concerns, we are soliciting 

comment on several proposed options to adjust the presumptive 

minimum fee provisions of the regulations, including an option 

that would calculate no additional costs for GHGs, a modest 

additional cost for each GHG-related activity of certain types 

that a permitting authority would process over the period 

covered by the presumptive minimum fee calculation, and a modest 

additional increase in the per ton rate used in the presumptive 

minimum calculation. 

When we promulgate step 4 of the Tailoring Rule, and 

depending on EPA’s proposal(s) and final action(s) there, we may 

revisit the GHG cost adjustment and potentially revise it, 

taking into account any changes in permitting authority costs 

for GHGs related to the obligations for permitting authorities 

under that rulemaking. 
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In addition, as a general matter, the presumptive minimum 

adjustments for part 70 we propose for GHGs are based, in part, 

on information concerning permitting authority burden (in hours) 

and cost (in dollars) contained in the Information Collection 

Request (ICR) renewal for part 70229 approved by the Office of 

Management and Budget on October 3, 2012 for the 36 month period 

of October 31, 2012 through September 30, 2015. Also, this 

information is consistent with, and updates, burden and cost 

information in the Regulatory Impact Assessment (RIA) for the 

Tailoring Rule230 and an ICR change request for the GHG Tailoring 

Rule (EPA ICR Number 1587.11), which was approved by OMB at the 

time of the promulgation of the Tailoring Rule231. These 

assumptions are relevant through step 3 of the implementation of 

the Tailoring Rule. The supporting statement for the ICR renewal 

for part 70 sets forth our estimate of the three-year and annual 

incremental burden related to certain activities performed by 

permitting authorities under the Tailoring Rule. (See Supporting 

Statement for the Part 70 state Operating Permits Program, 

 

229 The most recent part 70 ICR renewal is identified as EPA ICR 

number 1587.12 and the ICR for part 70 has been assigned OMB 

control number 2060-0243. 

230 Regulatory Impact Analysis for the Final Prevention of 

Significant Deterioration and Title V Greenhouse Gas Tailoring 

Rule, Final Report, May 2010.

231 The ICR change request form for the Tailoring Rule was based 

on the assumptions made in the RIA for the Tailoring Rule. 
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document number EPA-HQ-OAR-2004-0016-0023). The information in 

the supporting statement is designed to be a directionally 

correct assessment of costs, and thus, may serve as a starting 

point for considerations of the possible range of costs to 

consider when proposing adjustments to the presumptive minimum 

fee provisions of part 70 to appropriately account for GHG 

permitting program costs. 

We are proposing to adjust GHG costs by adding a cost for 

each GHG-related activity of certain types that a permitting 

authority may perform over the period covered by a presumptive 

minimum fee calculation. Additional information supporting this 

approach may be found in part in Table 12 of the supporting 

statement (in the ICR) summarizes the permitting authority 

burden for particular GHG-related permitting activities. Table 

12 in the ICR shows certain incremental burden assumptions for 

certain activities related to GHG permitting program costs in 

the form of an hourly burden for each activity that a permitting 

authority may process. Based on observations regarding 

permitting activities since the Tailoring Rule, we have adapted 

these assumptions for the purposes of this option and included 

certain activities with a somewhat different description than we 

used in the table in the ICR in an attempt to more accurately 
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reflect the types of permitting activities that have occurred in 

the GHG permit program. In addition, by making these clarifying 

changes, we are trying to more closely track the language in the 

CAA and parts 70 and 71 regarding the specific of the permit 

process. We are proposing to include three general activities 

in this proposed option: 1) “completeness determination (for new 

permits or for updated applications)” at 43 hours, 2) 

“modification at the facility or a permit that requires a GHG 

evaluation” at 7 hours, and 3) “evaluate GHG at permit renewal” 

at 10 burden hours.232 The GHG cost adjustment for the 

presumptive fee would be calculated under this approach by 

multiplying the burden hours for each activity by the cost of 

staff time (in $ per hour), including wages, benefits, and 

 

232 The first item, “completeness determination” is essentially 

the first step performed by the permitting authority once an 

application is submitted. See, e.g., 40 CFR 70.5(a)(2). The 

second item, “modification at the facility or a permit that 

requires a GHG evaluation” applies where a modification is 

occurring at the facility and the permitting authority is 

obligated to undertake an analysis of whether such modification 

triggered any GHG related requirements. This might occur, for 

example, where a synthetic or true minor application is 

submitted and the permitting authority needs to undertake a GHG 

related analysis. The third item, “evaluate GHG at permit 

renewal” applies where the permitting authority receives a 

renewal application that is not coupled with any facility 

modifications. EPA suggests this language because it is more 

closely tied to the specific work to be performed by permitting 

authorities consistent with statutory and regulatory 

obligations. 
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overhead, as determined by the state for the particular 

activities undertaken. 

 Note that some of these activities are one-time 

activities that may not extend beyond the expected end of step 3 

of the Tailoring Rule. 

 We are also co-proposing an alternative option under which 

we would increase the fee rate used in the presumptive minimum 

calculation for each regulated air pollutant, excluding GHGs. 

This option would rely primarily on data concerning the state 

burdens of permitting GHGs through step 3 of the tailoring rule 

found in the Information Collection Request (ICR) for part 70. 

This suggests that when looking at Tailoring Rule burdens in 

isolation, that GHG permitting increases permitting authority 

burden by about 7 percent233, which would be multiplied by the 

presumptive minimum fee rate in effect to calculate the revise 

presumptive fee rate to account for GHG. Under this approach, 

the new presumptive minimum fee effective for the current period 

would be $50.00 per ton for each regulated pollutant (for 

 

233 Table 14 shows 102,122 hours for GHG tailoring rule divided by 

1,414,293 hours baseline permitting authority cost (unadjusted) 

and Table 15 shows $5.5 million for GHG tailoring rule divided 

by $76.4 million for baseline permitting authority cost 

(unadjusted). 
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presumptive fee calculation)234. Several states suggested an 

approach similar to this in comments on the Tailoring Rule, 

however, their comments assumed we would not be exempting GHGs 

from the definition of regulated pollutants (for presumptive fee 

calculation), as we are proposing today. 

 We also solicit comment on whether we need to revise the 

presumptive minimum calculation provisions to account for GHGs 

costs if we exempt GHGs from the calculation of the presumptive 

minimum fee. The basis for this option would be that because 

most GHG sources that would be subject to title V permitting, 

whether due to GHGs or due for other reasons under the proposed 

NSPS and applicability provisions of the permitting rules (see 

40 CFR 70.3 and 71.3) would have actual emissions of other 

regulated air pollutants subject to fees, and thus the cost of 

permitting these sources may be adequately accounted for without 

charging any additional fees specifically based on emissions of 

GHGs. We also note that support for this approach can be found 

in the current OMB-approved ICR for part 70, tables 14, 15 and 

18, where the cost of permitting for permitting authorities is 

 

234 At the current rate for part 70 of $46.73, this would result 

in a GHG fee adjustment of about $3.27, or a new rate of $50.00 

per ton for each regulated pollutant (for presumptive fee 

calculation).
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summarized, considering the effects of several recent EPA 

rulemakings that were conducted since the last ICR update. 

This proposal does not directly affect those states that do 

not rely on the presumptive minimum fee approach to show fee 

adequacy (those that charge more than the presumptive minimum 

fee), however non-presumptive fee states are still required to 

charge sufficient fees to recover all reasonable direct and 

indirect program costs. Part 70 allows the EPA to review state 

fee programs at any time to determine if they are collecting 

fees sufficient to cover their costs, whether or not states rely 

on the presumptively minimum fee approach. We are not requiring 

any additional detailed fee submittals from states at this time 

based on these proposed changes. 

Some states may conclude that they wish to revise their 

part 70 programs in response to this proposal either to revise 

their state fee schedules to prevent any possible collection of 

excessive fees (e.g., if they require any regulated pollutant 

subject to a section 111 standard to pay a fee) or to charge 

additional fees to sources because their presumptive minimum fee 

target has increased. We solicit comment on the most expeditious 

means for EPA to approve title V program revisions across the 

states once this proposal is finalized. 
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In addition to the options for which comment is solicited 

above, there may be other viable options consistent with 

statutory and regulatory authority, principles, and concerns, 

that we have described in this proposal. For example, states 

have previously commented on a separate, lower presumptive fee 

per ton of GHG emissions). EPA invites states, local, and/or 

Tribal authorities to provide more refined data and/or 

information surrounding the unique costs associated with 

permitting GHG sources under this proposed rule, and other fee 

options such data supports. Notably, the regulatory text 

included today represents an option on which comments are 

solicited. EPA is also soliciting comment on other viable 

options described herein. EPA anticipates that sufficient 

information is provided in this preamble and the included 

regulatory text, to support EPA finalizing regulatory text on 

another option. 

c. Revisions to the part 71 fee schedule

As part of the promulgation of the final part 71 rule, the 

EPA performed a detailed analysis of the costs of developing and 

implementing the program and reviewed the inventory of emissions 

of regulated pollutants (for fee calculation) to determine the 

appropriate emission fee that would be sufficient to recover all 

direct and indirect programs costs – we set the fee at $32 per 
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ton, adjusted for inflation, times the emissions of regulated 

pollutant (for fee calculation). (See Federal Operating Programs 

Fees, Revised Cost Analysis, February 1996; legacy docket A-93-

51, document number II-A-3.) 

For part 71, we also propose to exempt GHGs from the 

definition of regulated pollutant (for fee calculation), which 

is similar to the definition of regulated pollutants (for 

presumptive fee calculation) used in part 70, for the same 

reasons we have explained for part 70. In addition, for the same 

reasons we explained for part 70, we are proposing two options 

for revising the fee schedule of 40 CFR 71.9(c) to ensure that 

we continue to recover sufficient fees to fully fund the part 71 

GHG permitting program. The bases for the options were 

described in more detail earlier in this proposal with respect 

to part 70 proposals and those also apply here to part 71. 

 

 First, the EPA (or delegate agency) burden hour assumptions 

we propose for each GHG-related permitting activity under part 

71 are the same as we are proposing for states under the 

presumptive minimum fee provisions of part 70.235 This option 

 

235 See the supporting statement for the ICR renewal for part 71 

approved by the Office of Management and Budget on June 13, 2012 

for the 36 month period of June 30, 2012 through May 31, 2015. 

The ICR renewal for part 71 is identified as EPA ICR number 
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would rely on the following information. The labor rate 

assumption we propose for the EPA (or delegate agency) staff 

time under part 71 is the average hourly rate we assumed in the 

supporting statement for the recent part 71 ICR renewal of $52 

per hour in 2011 dollars, including wages, benefits and overhead 

costs. We propose to determine the GHG fee adjustment for each 

GHG permitting program activity by multiplying the burden hour 

assumption we propose by the EPA (or delegate agency) labor rate 

we propose. Thus, for example, we propose a set fee to be paid 

by sources for each “completeness determination (for new permit 

or updated application” of $364 (7 hours times $52 per hour for 

the current period). Also, we propose to charge, for simplicity 

sake, the same set fees for GHG activities, whether performed by 

the EPA, a delegate agency, or by the EPA with contractor 

assistance. The appropriate set fees for all GHG permitting 

program activities performed for the source would be added to 

the traditional fee that is determined based on emissions of 

each regulated pollutants (for fee calculation) to determine the 

total fee for the source. 

 

1713.10 and the ICR for part 71 has been assigned OMB control 

number 2060-0336. The assumptions of this part 71 ICR renewal 

for GHG burden are identical to those used for the part 70 ICR. 

See Table 12 of the part 71 supporting statement. 
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 The second option we propose for part 71 is to increase the 

emission fee by a modest amount for each regulated air 

pollutant, excluding GHGs. For simplicity sake, we propose to 

charge the same adjustment under this option that we propose for 

part 70, or 7 percent, which would be multiplied by annual part 

71 fee in effect to calculate the revise fee rate236. The 

rationale for this approach is described in more detail earlier 

in this preamble during the part 70 discussion. 

We also solicit comment on whether we could exclude GHG 

emissions from the calculation of the the annual part 71 fee 

for reasons similar to those we explained for part 70 (e.g., 

because permitting costs can be covered by the existing part 71 

permit fee). 

 

236 At the current rate for part 71 of $48.33, this would result in 

a GHG fee adjustment of $3.38, or a new rate of $51.710 per ton 

for each regulated pollutant (for fee calculation).
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XI. Impacts of the Proposed Action 

A. What are the air impacts?

As explained in the Regulatory Impact Analysis (RIA) for 

this proposed rule, available data indicate that, even in the 

absence of this rule, existing and anticipated economic 

conditions will lead electricity generators to choose new 

generation technologies that would meet the proposed standard 

without installation of additional controls. Therefore, based on 

the analysis presented in Chapter 5 of the RIA, the EPA projects 

that this proposed rule will result in negligible CO2 emission 

changes, quantified benefits, and costs by 2020. 

B. What are the energy impacts?

This proposed rule is not anticipated to have a notable 

effect on the supply, distribution, or use of energy. As 

previously stated, the EPA believes that electric power 

companies would choose to build new EGUs that comply with the 

regulatory requirements of this proposal even in its absence, 

because of existing and expected market conditions. In addition, 

the EPA does not project any new coal-fired EGUs without CCS to 

be built in the absence of this proposal. 

C. What are the compliance costs?
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The EPA believes this proposed rule will have no notable 

compliance costs associated with it, because electric power 

companies would be expected to build new EGUs that comply with 

the regulatory requirements of this proposal even in the absence 

of the proposal, due to existing and expected market conditions. 

The EPA does not project any new coal-fired EGUs without CCS to 

be built in the absence of the proposal. However, because some 

companies may choose to construct coal or other fossil fuelfired units, the RIA also analyzes project-level costs of a unit 

with and without CCS, to quantify the potential cost for a 

fossil fuel-fired unit with CCS. 

D. How will this proposal contribute to climate change 

protection?

As previously explained, the special characteristics of 

GHGs make it important to take initial steps to control the 

largest emissions categories without delay. Unlike most 

traditional air pollutants, GHGs persist in the atmosphere for 

time periods ranging from decades to millennia, depending on the 

gas. Fossil-fueled power plants emit more GHG emissions than any 

other stationary source category in the United States, and among 

new GHG emissions sources, the largest individual sources are in 

this source category. 

This proposed rule will limit GHG emissions from new 
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sources in this source category to levels consistent with 

current projections for new fossil-fuel-fired generating units. 

The proposed rule will also serve as a necessary predicate for 

the regulation of existing sources within this source category 

under CAA section 111(d). In these ways, the proposed rule will 

contribute to the actions required to slow or reverse the 

accumulation of GHG concentrations in the atmosphere, which is 

necessary to protect against projected climate change impacts 

and risks. 

E. What are the economic and employment impacts?

 The EPA does not anticipate that this proposed rule will 

result in notable CO2 emission changes, energy impacts, monetized 

benefits, costs, or economic impacts by 2020. The owners of 

newly built electric generating units will likely choose 

technologies that meet these standards even in the absence of 

this proposal due to existing economic conditions as normal 

business practice. 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 of the proposed standards?

 As previously stated, the EPA does not anticipate that the 

power industry will incur compliance costs as a result of this 

proposal and we do not anticipate any notable CO2 emission 
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changes resulting from the rule. Therefore, there are no direct 

monetized climate benefits in terms of CO2 emission reductions 

associated with this rulemaking. However, by clarifying that in 

the future, new coal-fired power plants will be required to meet 

a particular performance standard, this rulemaking reduces 

uncertainty and may enhance the prospects for new coal-fired 

generation and the deployment of CCS, and thereby promote energy 

diversity. 

XII. Request for Comments 

We request comments on all aspects of the proposed 

rulemaking including the RIA. All significant comments received 

will be considered in the development and selection of the final 

rule. We specifically solicit comments on additional issues 

under consideration as described below. 

Measurement. We are requesting comment on requiring the use 

the following procedures that increase the precision of GHG 

measurements: 

a. EPA Method 2F of 40 CFR part 60 for flow rate 

measurement during the relative accuracy test audit and 

performance testing. Method 2F provides velocity data for three 

dimensions and provides measurements more representative of 

actual gas flow rates than EPA Method 2 or 2G of 40 CFR part 60. 
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b. EPA Method 2H of 40 CFR part 60 or Conditional Test 

Method (CTM)-041 (see: 

http://www.epa.gov/airmarkets/emissions/docs/square-ducts-walleffects-test-method-ctm-041.pdf) to account for wall effects on 

for stack gas flow rate calculations during CEMS relative 

accuracy determinations and for performance testing. 

c. EPA Method 4 of 40 CFR part 60 to determine moisture for 

flow rate during CEMS relative accuracy determinations and for 

performance test calculations. 

d. EPA Method 3A of 40 CFR part 60 for CO2 concentration 

measurement and for molecular weight determination during CEMS 

relative accuracy determinations or for performance testing. 

e. An ambient air argon concentration of 0.93 percent[1] and 

a molecular weight of 39.9 lb/lb-mol in calculating the dry gas 

molecular weight. 

f. A value for pi of 3.41159 when calculating the effective 

area for circular stacks. 

g. A daily calibration drift cap no greater than 0.3 

percent CO2 for CO2 CEMS. 

h. A maximum relative accuracy specification of 2.5 percent 

for both CO2 and flow rate measurement CEMS. 

 

[1] http://www.physicalgeography.net/fundamentals/7a.html.
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i. Method 3B of 40 CFR part 60 in addition to Method 3A, 

for CO2 concentration measurement and for molecular weight 

determination during CEMS relative accuracy determinations or 

for performance testing. 

Coal refuse. Due to the multiple environmental benefits of 

remediating coal refuse piles, we requested comment in the 

previous proposal on subcategorizing EGUs that burn over 75 

percent coal refuse on an annual basis. Multiple commenters on 

the previous proposal supported the exemption citing the 

environmental benefits of remediating coal refuse piles. 

Commenters on the previous proposal also disagreed with any 

exemption, specifically siting the N2O emissions from fluidized 

bed boilers. Due to the environmental benefits of remediating 

coal refuse piles, the limited amount of coal refuse, and the 

fact that a new coal refuse-fired EGU would have to be located 

in close proximity to the coal refuse pile, we are continuing to 

consider establishing a subcategory for coal refuse-fired EGUs 

and are requesting additional comments. Specifically, we are 

requesting additional information on the net environmental 

benefits of coal refuse-fired EGUs, and in the event we do 

establish a coal refuse-fired subcategory, what the emissions 

standard for that subcategory should be. One commenter on the 

previous proposal stated that existing coal refuse piles are 
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naturally combusting at a rate of 0.3 percent annually. We are 

requesting comment on assuming this rate of natural combustion 

and the proper approach to accounting for naturally occurring 

emissions from coal refuse piles. 

Compressed Air Energy Storage (CAES) Facilities. The EPA is 

considering and requesting comment on exempting stationary 

combustion turbines at compressed air energy storage facilities 

from the CO2 emissions standard. CAES technology involves two 

steps. Air is compressed by electric motor driven compressors 

during off-peak electricity demand hours and stored in a storage 

media (e.g., an underground cavern). Electricity is then 

generated during peak electricity demand periods by releasing 

the high‐pressure air, heating the air with natural gas, and 

expanding it through sequential turbines (expanders), which 

drive an electrical generator. Since natural gas is combusted in 

the stationary combustion turbine, a new CAES facility meeting 

the general applicability requirements would have to comply with 

an emissions standard. However, the use of stored energy 

complicates determining compliance with the proposed emission 

standards. Since we only expect a limited number of new CAES 

facilities, we have concluded that the new source review program 

is the appropriate mechanism to establish site specific GHG 

requirements for such sources. 
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District Energy. Even though with the proposed definition 

of net-electric output it is unlikely that a district energy 

system would be subject to an emissions standard, we are 

considering and requesting comment on an appropriate method to 

recognize the environmental benefit of district energy systems. 

The steam or hot water distribution system of a district energy 

system located in urban areas, college and university campuses, 

hospitals, airports, and military installations eliminates the 

need for multiple, smaller boilers at individual buildings. A 

central facility typically has superior emission controls and 

consists of a few larger boilers facilitating more efficient 

operation than numerous separate smaller individual boilers. 

However, when the hot water or steam is distributed, 

approximately two to three percent of the thermal energy in the 

water and six to nine percent of the thermal energy in the steam 

is lost, reducing the net efficiency advantage. We are 

requesting comment on whether it is appropriate to divide the 

thermal output from district energy systems by a factor (i.e., 

0.95 or 0.90) that would account for the net efficiency benefits 

of district energy systems. This approach would be similar to 

the proposed approach to how the electric output for CHP is 

considered when determining regulatory compliance and is 

consistent with the approach in the proposed amendments to the 
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combustion turbine NSPS (77 FR 52554). We request that comments 

include technical analysis of the net benefits in support of any 

conclusions. 

Emergency conditions. We are requesting comment on 

excluding electricity generated as a result of a grid emergency 

declared by the Regional Transmission Organizations (RTO), 

Independent System Operators (ISO) or control area Administrator 

(e.g., grid voltage would drop below acceptable levels and the 

affected facility is the only facility with additional available 

capacity) from counting as net sales when determining 

applicability as an EGU. While the proposed 3 year average 

electric sales applicability provides significant flexibility 

for simple cycle turbines, we are considering including the 

emergency conditions exemption to allow facilities designed with 

the intent to sell less than 1/3 of their potential electric 

output to continue to generate electricity during a grid 

emergency without such generation counting towards the 1/3 sales 

applicability criterion. In the original electric utility NSPS 

rulemaking, the EPA recognized that emergency periods do occur 

from unplanned EGU outages, transmission outages or surging 

customer demand loads. Such occurences may require that all 

available operable EGUs interconnected to the electrical grid 

supply power to the grid. Provisions were added to 40 CFR 60 
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subpart Da to address emergency conditions when continued 

operation of an EGU with a malfunctioning flue gas 

desulfurization (FGD) system is acceptable and not considered a 

violation of the SO2 emissions standard. These conditions require 

that all available capacity from the power company’s other EGUs 

is being used and all available purchase power from 

interconnected power companies is being obtained. In this case, 

the EPA concluded that the broader benefits of operating the 

power plant with the malfunctioning FGD system to generate 

electrical power during emergency conditions in order to ensure 

uninterrupted electricity supply to the public outweigh any 

adverse impacts from a short-term increase in SO2 emission to the 

atmosphere from the power plant.

Initial Design Efficiency Test. We are considering and 

requesting comment on requiring an initial performance test for 

stationary combustion turbines in addition to the 12-operatingmonth rolling average standard. Requiring an initial compliance 

test that is numerically more stringent than the annual standard 

for new combined cycle facilities would insure that the most 

efficient stationary combustion turbines are installed. The less 

stringent 12-month rolling average standard would be set at a 

level that would take into account actual operating conditions.
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Integrated Equipment. The proposed affected facility 

definition includes the stationary combustion turbine/steam 

generating unit “plus any integrated equipment that provides 

electricity or useful thermal output.” We are considering and 

requesting comment on also including co-located non-emitting 

energy generation equipment that is not integrated into the 

operation of the affected facility in the definition of the 

affected facility. This approach would provide additional 

flexibility, lower compliance costs, and recognize the 

environmental benefit of non-emitting sources of electricity and 

not limit options to solar thermal feedwater heating. The 

definition would include the additional language “or co-located 

non-emitting energy generation included in the facility 

operating permit.” This would permit the use of co-located 

photovoltaic solar power, wind turbines, and other non-emitting 

energy generation as means for achieving compliance with the 

emission standards. Since integrated solar thermal feedwater 

heating is primarily only a feasible option for facilities that 

operate daily, this approach would expand options for more 

intermittent intermediate load generators to efficiently 

integrate non-emitting energy generation into their design.

Net-output-based standards. We are considering and 

requesting comment on adding an optional net-output based 
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standard for each subcategory. As described in the previous 

proposal, net output is the combination of the gross electrical 

output of the electric generating unit minus the parasitic power 

requirements. A parasitic load for an electric generating unit 

is any of the loads or devices powered by electricity, steam, 

hot water, or directly by the gross output of the electric 

generating unit that does not contribute electrical, mechanical, 

or thermal output. In general, less than 7.5 percent of non-IGCC 

and non-CCS coal-fired station power output, approximately 15 

percent of non-CSS IGCC-based coal-fired station power output 

and about 2.5 percent of non-CCS combined cycle station power 

output is used internally by parasitic energy demands, but the 

amount of these parasitic loads vary from source to source. 

Reasons for using net output include (1) recognizing the 

efficiency gains of selecting EGU designs and control equipment 

that require less auxiliary power, (2) selecting fuels that 

require less emissions control equipment, and (3) recognizing 

the environmental benefit of higher efficiency motors, pumps, 

and fans. While the EPA has concluded that the net power 

supplied to the end user is a better indicator of environmental 

performance than gross output from the power producer, we only 

have CEMS emissions data reported on a gross output basis. In 

addition, for facilities that coproduce chemicals and other 

Comment [A126]: It would be helpful if EPA 

could explain why it only has CEMS emission data 

reported on a gross output basis and why the agency 

is not able to move to a more optimal parasitic 

accounting approach. 
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useful byproducts, accurate accounting of the parasitic loads 

could be problematic. The optional net-output based standard 

would have the most impact for non-IGCC-based coal-fired EGUs. 

While the net output based emissions rate for all non-CCS coalfired generation is similar, IGCC facilities have substantially 

larger parasitic loads and correspondingly lower gross emissions 

rates. The optional net-output based CO2 emissions rate for steam 

generating units and IGCC facilities corresponding to an 

emissions rate of 1,100 lb CO2/MWh on a gross basis would be 

1,400 lb CO2/MWh. The net-output based rate for stationary 

combustion turbines would be 1,030 lb CO2/MWh and 1,130 lb 

CO2/MWh for the large and small subcategory respectively. 

Other GHGs. Today’s proposed rule would require continuous 

measurement of CO2 from fossil fuel-fired EGUs. Other GHGs, such 

as methane (CH4) and nitrous oxide (N2O) are not included in the 

proposed emission standards and are also not required to be 

measured and reported by affected EGUs as part of today’s 

proposal, even though their 100-year global warming potential is 

21 to 310 times greater than that of CO2, because their emissions 

from EGUs are believed to be negligible when compared to CO2

emissions. We request comment on the appropriateness, technique, 

and frequency (one-time or periodic, but not continuous) of 

measurement and reporting of CH4 and N2O emissions from fossil 
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fuel-fired EGUs as part of the proposed emissions standard. 

Receipt of this data would enhance understanding of total GHG 

emissions from EGUs and could aid future policy decisions 

regarding whether these GHGs should be included in a revised 

emission standard, as part of 8-year NSPS review and potential 

revision cycle. 

Violations. We are proposing that the calculation of the 

number of daily violations within an averaging period be 

determined using the following methodology. The number of daily 

violations in a 12-operating-month or 60-operating-month 

averaging period would be the number of operating days in that 

averaging period. However, if a violation occurs directly 

following the previous 12-operating-month or 60-operating-month 

averaging period, daily violations would not double count 

operating days that were determined as violations under the 

previous averaging period. For example, if a facility operations 

10 days of month for 12 months and exceeds the emissions 

standard. The initial violation would constitute 120 daily 

violations. If the facility operated 20 days the following month 

and was still in excess of the emissions standard, 20 additional 

daily violations would result for a total of 140 daily 

violations. We are requesting comment on this determination of 
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daily violations for owners/operators that exceeds either a 12-

operating-month or 60-operating-month standard. 

XIII. Statutory and Executive Order Reviews 

A. Executive Order 12866, Regulatory Planning and Review, and 

Executive Order 13563, Improving Regulation and Regulatory 

Review

 Under Executive Order (EO) 12866 (58 FR 51,735, October 4, 

1993), this action is a “significant regulatory action” because 

it “raises novel legal or policy issues arising out of legal 

mandates”. Accordingly, the EPA submitted this action to the 

Office of Management and Budget (OMB) for review under Executive 

Orders 12866 and 13563 (76 FR 3821, January 21, 2011) and any 

changes made in response to OMB recommendations have been 

documented in the docket for this action. In addition, the EPA 

prepared an analysis of the potential costs and benefits 

associated with this action. This analysis is contained in the 

Regulatory Impact Analysis for the Standards of Performance for 

Greenhouse Gas Emissions for New Fossil Fuel-Fired Electric 

Utility Steam Generating Units and Stationary Combustion 

Turbines. 

 The EPA believes this rule will have no notable compliance 

costs associated with it over a range of likely sensitivity 

conditions because electric power companies would choose to 
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build new EGUs that comply with the regulatory requirements of 

this proposal even in the absence of the proposal, because of 

existing and expected market conditions. (See the RIA for 

further discussion of sensitivities). The EPA does not project 

any new coal-fired EGUs without CCS to be built in the absence 

of this proposal. However, because some companies may choose to 

construct coal or other fossil fuel-fired units, the RIA also 

analyzes project-level costs of a unit with and without CCS, to 

quantify the potential cost for a fossil fuel-fired unit with 

CCS. 

B. Paperwork Reduction Act

 The information collection requirements in this proposed 

rule have been submitted for approval to the Office of 

Management and Budget (OMB) under the Paperwork Reduction Act, 

44 U.S.C. 3501 et seq. The Information Collection Request (ICR) 

document prepared by the EPA has been assigned the EPA ICR 

number 2465.01.

 This proposed action would impose minimal new information 

collection burden on affected sources beyond what those sources 

would already be subject to under the authorities of CAA parts 

75 and 98. OMB has previously approved the information 

collection requirements contained in the existing part 75 and 98 

regulations (40 CFR part 75 and 40 CFR part 98) under the 
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provisions of the Paperwork Reduction Act, 44 U.S.C. 3501 et

seq. and has assigned OMB control numbers 2060-0626 and 2060-

0629, respectively. Apart from certain reporting costs based on 

requirements in the NSPS General Provisions (40 CFR part 60, 

subpart A), which are mandatory for all owners/operators subject 

to CAA section 111 national emission standards, there are no new 

information collection costs, as the information required by 

this proposed rule is already collected and reported by other 

regulatory programs. The recordkeeping and reporting 

requirements are specifically authorized by CAA section 114 (42 

U.S.C. 7414). All information submitted to the EPA pursuant to 

the recordkeeping and reporting requirements for which a claim 

of confidentiality is made is safeguarded according to Agency 

policies set forth in 40 CFR part 2, subpart B. 

The EPA believes that electric power companies will choose 

to build new EGUs that comply with the regulatory requirements 

of this proposal because of existing and expected market 

conditions. The EPA does not project any new coal-fired EGUs 

that commence construction after this proposal to commence 

operation over the three-year period covered by this ICR. We 

estimate that 17 new affected NGCC units would commence 

operation during that time period. As a result of this proposal, 

those units would be required to prepare a summary report, which 
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includes reporting of excess emissions and downtime, every six 

months.

When a malfunction occurs, sources must report them 

according to the applicable reporting requirements of 40 CFR 

part 60, subpart Da or subpart KKKK. An affirmative defense to 

civil penalties for exceedances of emission limits that are 

caused by malfunctions is available to a source if it can 

demonstrate that certain criteria and requirements are 

satisfied. The criteria ensure that the affirmative defense is 

available only where the event that causes an exceedance of the 

emission limit meets the narrow definition of malfunction 

(sudden, infrequent, not reasonably preventable, and not caused 

by poor maintenance or careless operation) and where the source 

took necessary actions to minimize emissions. In addition, the 

source must meet certain notification and reporting 

requirements. For example, the source must prepare a written 

root cause analysis and submit a written report to the 

Administrator documenting that it has met the conditions and 

requirements for assertion of the affirmative defense. 

To provide the public with an estimate of the relative 

magnitude of the burden associated with an assertion of 

affirmative defense, the EPA has estimated what the 

notification, recordkeeping, and reporting requirements 
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associated with the assertion of the affirmative defense might 

entail. The EPA’s estimate for the required notification, 

reports, and records, including the root cause analysis, 

associated with a single incident totals approximately totals 

$3,141, and is based on the time and effort required of a source 

to review relevant data, interview plant employees, and document 

the events surrounding a malfunction that has caused an 

exceedance of an emission limit. The estimate also includes time 

to produce and retain the record and reports for submission to 

the EPA. The EPA provides this illustrative estimate of this 

burden, because these costs are only incurred if there has been 

a violation, and a source chooses to take advantage of the 

affirmative defense. 

Given the variety of circumstances under which malfunctions 

could occur, as well as differences among sources' operation and 

maintenance practices, we cannot reliably predict the severity 

and frequency of malfunction-related excess emissions events for 

a particular source. It is important to note that the EPA has no 

basis currently for estimating the number of malfunctions that 

would qualify for an affirmative defense. Current historical 

records would be an inappropriate basis, as this rule applies 

only to sources built in the future. Of the number of excess 

emissions events that may be reported by source operators, only 
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a small number would be expected to result from a malfunction, 

and only a subset of excess emissions caused by malfunctions 

would result in the source choosing to assert an affirmative 

defense. Thus, we believe the number of instances in which 

source operators might be expected to avail themselves of the 

affirmative defense will be extremely small. In fact, we 

estimate that there will be no such occurrences for any new 

sources subject to 40 CFR part 60, subpart Da or subpart KKKK 

over the three-year period covered by this ICR. We expect to 

gather information on such events in the future, and will revise 

this estimate as better information becomes available. 

The annual information collection burden for this 

collection consists only of reporting burden as explained above. 

The reporting burden for this collection (averaged over the 

first three years after the effective date of the standards) is 

estimated to be $15,570 and 396 labor hours. This estimate 

includes semi-annual summary reports which include reporting of 

excess emissions and downtime. All burden estimates are in 2010 

dollars. Average burden hours per response are estimated to be 

16.5 hours. The total number of respondents over the three-year 

ICR period is estimated to be 36. Burden is defined at 5 CFR 

1320.3(b). 
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An agency may not conduct or sponsor, and a person is not 

required to respond to, a collection of information unless it 

displays a currently valid OMB control number. The OMB control 

numbers for the EPA's regulations in 40 CFR are listed in 40 CFR 

part 9. 

 To comment on the Agency's need for this information, the 

accuracy of the provided burden estimates, and any suggested 

methods for minimizing respondent burden, the EPA has 

established a public docket for this rule, which includes this 

ICR, under Docket ID number EPA-HQ-OAR-2013-0495. Submit any 

comments related to the ICR to the EPA and OMB. See ADDRESSES

section at the beginning of this notice for where to submit 

comments to the EPA. Send comments to OMB at the Office of 

Information and Regulatory Affairs, Office of Management and 

Budget, 725 17th Street, NW, Washington, DC 20503, Attention: 

Desk Officer for the EPA. Since OMB is required to make a 

decision concerning the ICR between 30 and 60 days after [INSERT 

DATE OF PUBLICATION IN THE FEDERAL REGISTER], a comment to OMB 

is best assured of having its full effect if OMB receives it by 

[INSERT DATE 30 DAYS AFTER PUBLICATION IN THE FEDERAL REGISTER]. 

The final rule will respond to any OMB or public comments on the 

information collection requirements contained in this proposal. 

C. Regulatory Flexibility Act as Amended by the Small Business 
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Regulatory Enforcement Fairness Act of 1996, 5 U.S.C. et seq.

The Regulatory Flexibility Act (RFA) generally requires an 

agency to prepare a regulatory flexibility analysis of any rule 

subject to notice and comment rulemaking requirements under the 

Administrative Procedure Act or any other statute unless the 

agency certifies that the rule will not have a significant 

economic impact on a substantial number of small entities. Small 

entities include small businesses, small organizations, and 

small governmental jurisdictions. 

For purposes of assessing the impacts of this rule on small 

entities, small entity is defined as: 

(1) A small business that is defined by the SBA’s 

regulations at 13 CFR 121.201 (for the electric power generation 

industry, the small business size standard is an ultimate parent 

entity defined as having a total electric output of 4 million 

MWh or less in the previous fiscal year. The NAICS codes for the 

affected industry are in Table 5 below); 

(2) A small governmental jurisdiction that is a government 

of a city, county, town, school district or special district 

with a population of less than 50,000; and 

(3) A small organization that is any not-for-profit 

enterprise which is independently owned and operated and is not 

dominant in its field. 
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Table 5. Potentially Regulated Categories and Entitiesa

 

Category NAICS 

Code 

Examples of Potentially Regulated 

Entities 

Industry 

 

221112 

 

Fossil fuel electric power generating 

units. 

Federal 

Government 

 

221112b

 

Fossil fuel electric power generating 

units owned by the federal government.

State/Local 

Government 

 

221112b

 

Fossil fuel electric power generating 

units owned by municipalities. 

Tribal 

Government 921150 Fossil fuel electric power generating 

units in Indian Country. 

a

 Include NAICS categories for source categories that own and 

operate electric power generating units (includes boilers and 

stationary combined cycle combustion turbines). 

b

 Federal, state, or local government-owned and operated 

establishments are classified according to the activity in which 

they are engaged. 

After considering the economic impacts of this proposed 

rule on small entities, I certify that this action will not have 

a significant economic impact on a substantial number of small 

entities. 

We do not include an analysis of the illustrative impacts 

on small entities that may result from implementation of this 

proposed rule because we do not anticipate any compliance costs 

over a range of likely sensitivity conditions as a result of 

this proposal. Thus the cost-to-sales ratios for any affected 
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small entity would be zero costs as compared to annual sales 

revenue for the entity. The EPA believes that electric power 

companies will choose to build new EGUs that comply with the 

regulatory requirements of this proposal because of existing and 

expected market conditions. (See the RIA for further discussion 

of sensitivities). The EPA does not project any new coal-fired 

EGUs without CCS to be built. Accordingly, there are no 

anticipated economic impacts as a result of this proposal. 

Nevertheless, the EPA is aware that there is substantial 

interest in this rule among small entities (municipal and rural 

electric cooperatives). In light of this interest, prior to the 

April 13, 2012 proposal (77 FR 22392), the EPA determined to 

seek early input from representatives of small entities while 

formulating the provisions of the proposed regulation. Such 

outreach is also consistent with the President’s January 18, 

2011 Memorandum on Regulatory Flexibility, Small Business, and 

Job Creation, which emphasizes the important role small 

businesses play in the American economy. This process has 

enabled the EPA to hear directly from these representatives, at 

a very preliminary stage, about how it should approach the 

complex question of how to apply Section 111 of the CAA to the 

regulation of GHGs from these source categories. The EPA’s 

outreach regarded planned actions for new and existing sources, 
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but only new sources would be affected by this proposed action. 

The EPA conducted an initial outreach meeting with small 

entity representatives on April 6, 2011. The purpose of the 

meeting was to provide an overview of recent EPA proposals 

impacting the power sector. Specifically, overviews of the 

Transport Rule, the Mercury and Air Toxics Standards, and the 

Clean Water Act 316(b) Rule proposals were presented. 

The EPA conducted outreach with representatives from 20 

various small entities that potentially would be affected by 

this rule. The representatives included small entity 

municipalities, cooperatives, and private investors. We 

distributed outreach materials to the small entity 

representatives; these materials included background, an 

overview of affected sources and GHG emissions from the power 

sector, an overview of CAA section 111, an assessment of CO2

emissions control technologies, potential impacts on small 

entities, and a summary of the listening sessions. We met with 

eight of the small entity representatives, as well as three 

participants from organizations representing power producers, on 

June 17, 2011, to discuss the outreach materials, potential 

requirements of the rule, and regulatory areas where the EPA has 

discretion and could potentially provide flexibility. 
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A second outreach meeting was conducted on July 13, 2011. 

We met with nine of the small entity representatives, as well as 

three participants from organizations representing power 

producers. During the second outreach meeting, various small 

entity representatives and participants from organizations 

representing power producers presented information regarding 

issues of concern with respect to development of standards for 

GHG emissions. Specifically, topics suggested by the small 

entity representatives and discussed included: boilers with 

limited opportunities for efficiency improvements due to NSR 

complications for conventional pollutants; variances per 

kilowatt-hour and in heat rates over monthly and annual 

operations; significance of plant age; legal issues; importance 

of future determination of carbon neutrality of biomass; and 

differences between municipal government electric utilities and 

other utilities. 

While formulating the provisions of this proposed 

regulation, the EPA also considered the input provided in the 

over 2.5 million public comments on the April 13, 2012 proposed 

rule (77 FR 22392). We invite comments on all aspects of the 

proposal and its impacts, including potential adverse impacts, 

on small entities. 

D. Unfunded Mandates Reform Act of 1995
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This proposed rule does not contain a federal mandate that 

may result in expenditures of $100 million or more for State, 

local, and tribal governments, in the aggregate, or the private 

sector in any one year. The EPA believes this proposed rule will 

have no compliance costs associated with it over a range of likely 

sensitivity conditions because electric power companies will 

choose to build new EGUs that comply with the regulatory 

requirements of this proposal because of existing and expected 

market conditions. (See the RIA for further discussion of 

sensitivities). The EPA does not project any new coal-fired EGUs 

without CCS to be built. Thus, this proposed rule is not subject 

to the requirements of sections 202 or 205 of UMRA. 

This proposed rule is also not subject to the requirements 

of section 203 of UMRA because it contains no regulatory 

requirements that might significantly or uniquely affect small 

governments. 

In light of the interest in this rule among governmental 

entities, the EPA initiated consultations with governmental 

entities prior to the April 13, 2012 proposal (77 FR 22392). The 

EPA invited the following 10 national organizations representing 

state and local elected officials to a meeting held on April 12, 

2011, in Washington DC: 1) National Governors Association; 2) 

National Conference of State Legislatures, 3) Council of State 
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Governments, 4) National League of Cities, 5) U.S. Conference of 

Mayors, 6) National Association of Counties, 7) International 

City/County Management Association, 8) National Association of 

Towns and Townships, 9) County Executives of America, and 10) 

Environmental Council of States. These 10 organizations 

representing elected state and local officials have been 

identified by the EPA as the “Big 10” organizations appropriate 

to contact for purpose of consultation with elected officials. 

The purposes of the consultation were to provide general 

background on the proposal, answer questions, and solicit input 

from state/local governments. The EPA’s consultation regarded 

planned actions for new and existing sources, but only new 

sources would be affected by this proposed action. 

During the meeting, officials asked clarifying questions 

regarding CAA section 111 requirements and efficiency 

improvements that would reduce CO2 emissions. In addition, they 

expressed concern with regard to the potential burden associated 

with impacts on state and local entities that own/operate 

affected utility boilers, as well as on state and local entities 

with regard to implementing the rule. Subsequent to the April 

12, 2011 meeting, the EPA received a letter from the National 

Conference of State Legislatures. In that letter, the National 

Conference of State Legislatures urged the EPA to ensure that 
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the choice of regulatory options maximizes benefit and minimizes 

implementation and compliance costs on state and local 

governments; to pay particular attention to options that would 

provide states with as much flexibility as possible; and to take 

into consideration the constraints of the state legislative 

calendars and ensure that sufficient time is allowed for state 

actions necessary to come into compliance. 

While formulating the provisions of this proposed 

regulation, the EPA also considered the input provided in the 

over 2.5 million public comments on the April 13, 2012 proposed 

rule (77 FR 22392). 

E. Executive Order 13132, Federalism

This proposed action does not have federalism implications. 

It would 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, as specified in EO 13132. This 

proposed action would not impose substantial direct compliance 

costs on state or local governments, nor would it preempt state 

law. Thus, Executive Order 13132 does not apply to this action. 

Prior to the April 13, 2012 proposal (77 FR 22392), the EPA 

consulted with state and local officials in the process of 

developing the proposed rule to permit them to have meaningful 
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and timely input into its development. The EPA’s consultation 

regarded planned actions for new and existing sources, but only 

new sources would be affected by this proposed action. The EPA 

met with 10 national organizations representing state and local 

elected officials to provide general background on the proposal, 

answer questions, and solicit input from state/local 

governments. The UMRA discussion in this preamble includes a 

description of the consultation. While formulating the 

provisions of this proposed regulation, the EPA also considered 

the input provided in the over 2.5 million public comments on 

the April 13, 2012 proposed rule (77 FR 22392). In the spirit of 

EO 13132, and consistent with the EPA policy to promote 

communications between the EPA and state and local governments, 

the EPA specifically solicits comment on this proposed action 

from state and local officials. 

F. Executive Order 13175, Consultation and Coordination with 

Indian Tribal Governments

Subject to the EO 13175 (65 FR 67249, November 9, 2000) the 

EPA may not issue a regulation that has tribal implications, 

that imposes substantial direct compliance costs, and that is 

not required by statute, unless the federal government provides 

the funds necessary to pay the direct compliance costs incurred 

by tribal governments, or the EPA consults with tribal officials 
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early in the process of developing the proposed regulation and 

develops a tribal summary impact statement. 

The EPA has concluded that this proposed action would not 

have tribal implications. It would neither impose substantial 

direct compliance costs on tribal governments, nor preempt 

Tribal law. This proposed rule would impose requirements on 

owners and operators of new EGUs. 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 proposal does not affect existing sources such as the 

three coal-fired EGUs located in Indian Country, but addresses 

CO2 emissions for new EGU sources only. 

Because the EPA is aware of Tribal interest in this 

proposed rule, prior to the April 13, 2012 proposal (77 FR 

22392), the EPA offered consultation with tribal officials early 

in the process of developing the proposed regulation to permit 

them to have meaningful and timely input into its development. 

The EPA’s consultation regarded planned actions for new and 

existing sources, but only new sources would be affected by this 

proposed action. 

Consultation letters were sent to 584 tribal leaders. The 

letters provided information regarding the EPA’s development of 

NSPS and emission guidelines for EGUs and offered consultation. 
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A consultation/outreach meeting was held on May 23, 2011, with 

the Forest County Potawatomi Community, the Fond du Lac Band of 

Lake Superior Chippewa Reservation, and the Leech Lake Band of 

Ojibwe. Other tribes participated in the call for information 

gathering purposes. In this meeting, the EPA provided background 

information on the GHG emission standards to be developed and a 

summary of issues being explored by the Agency. Tribes suggested 

that the EPA consider expanding coverage of the GHG standards to 

include combustion turbines, lowering the 250 MMBtu per hour 

heat input threshold so as to capture more EGUs, and including 

credit for use of renewables. The tribes were also interested in 

the scope of the emissions averaging being considered by the 

Agency (e.g., over what time period, across what units). In 

addition, the EPA held a series of listening sessions on this 

proposed action. Tribes participated in a session on February 

17, 2011 with the state agencies, as well as in a separate 

session with tribes on April 20, 2011. 

While formulating the provisions of this proposed 

regulation, the EPA also considered the input provided in the 

over 2.5 million public comments on the April 13, 2012 proposed 

rule (77 FR 22392). 

The EPA will also hold additional meetings with tribal 

environmental staff to inform them of the content of this 
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proposal as well as provide additional consultation with tribal 

elected officials where it is appropriate. We specifically 

solicit additional comment on this proposed rule from tribal 

officials. 

G. Executive Order 13045, Protection of Children from 

Environmental Health Risks and Safety Risks

The EPA interprets EO 13045 (62 FR 19885, April 23, 1997) 

as applying to those regulatory actions that concern health or 

safety risks, such that the analysis required under section 5-

501 of the Order has the potential to influence the regulation. 

This proposed action is not subject to EO 13045 because it is 

based solely on technology performance. The proposal is not 

expected to produce notable changes in emissions of greenhouse 

gases or other pollutants but does encourage the current trend 

towards cleaner generation, helping to protect air quality and 

children's health. The Agency recognizes that children are among 

the groups most vulnerable to climate change impacts and the 

public is invited to submit comments or identify peer reviewed 

studies relevant to this proposal.

H. Executive Order 13211, Actions Concerning Regulations That 

Significantly Affect Energy Supply, Distribution, or Use

This proposed action is not a “significant energy action” 

as defined in EO 13211 (66 FR 28355 (May 22, 2001)) because it 
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is not likely to have a significant adverse effect on the 

supply, distribution, or use of energy. This proposed action is 

not anticipated to have notable impacts on emissions, costs or 

energy supply decisions for the affected electric utility 

industry. 

I. National Technology Transfer and Advancement Act 

Section 12(d) of the NTTAA of 1995 (Public Law No. 104-113; 

15 U.S.C. 272 note) directs the EPA to use Voluntary Census 

Standards in their regulatory and procurement activities unless 

to do so would be inconsistent with applicable law or otherwise 

impractical. Voluntary consensus standards are technical 

standards (e.g., materials specifications, test methods, 

sampling procedures, business practices) developed or adopted by 

one or more voluntary consensus bodies. The NTTAA directs the 

EPA to provide Congress, through annual reports to the OMB, with 

explanations when an agency does not use available and 

applicable VCS. 

This proposed rulemaking involves technical standards. The 

EPA cites the following standards in this proposed rule: D5287-

08 (Standard Practice for Automatic Sampling of Gaseous Fuels), 

D4057-06 (Standard Practice for Manual Sampling of Petroleum and 

Petroleum Products), and D4177-95(2010) (Standard Practice for 

Automatic Sampling of Petroleum and Petroleum Products). The EPA 
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is proposing use of Appendices B, D, F, and G to 40 CFR part 75; 

these Appendices contain standards that have already been 

reviewed under the NTTAA. 

The EPA welcomes comments on this aspect of the proposed 

rulemaking and, specifically, invites the public to identify 

potentially-applicable VCS and to explain why such standards 

should be used in this action. 

J. Executive Order 12898: Federal Actions to Address 

Environmental Justice in Minority Populations and Low-Income 

Populations

 Executive Order 12898 (59 FR 7629, February 16, 1994) 

establishes federal executive policy on environmental justice. 

Its main provision directs federal agencies, to the greatest 

extent practicable and permitted by law, to make environmental 

justice part of their mission by identifying and addressing, as 

appropriate, disproportionately high and adverse human health or 

environmental effects of their programs, policies, and 

activities on minority populations and low-income populations in 

the U.S. 

This proposed rule limits GHG emissions from new fossil 

fuel-fired EGUs by establishing national emission standards for 

CO2. The EPA has determined that this proposed rule would not 

result in disproportionately high and adverse human health or 
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environmental effects on minority, low-income, and indigenous 

populations because it increases the level of environmental 

protection for all affected populations without having any 

disproportionately high and adverse human health or 

environmental effects on any population, including any minority, 

low-income or indigenous populations.
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Standards of Performance for Greenhouse Gas Emissions from New 

Stationary Sources: Electric Utility Generating Units

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List of Subjects in 40 CFR Part 60

Environmental protection, Administrative practice and 

procedure, Air pollution control, Intergovernmental relations, 

Reporting and recordkeeping requirements. 

___________________ 

Dated:[add signature date] 

____________________ 

[Insert name here] 

[Acting?] Administrator 
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For the reasons stated in the preamble, title 40, chapter I, 

part 60, 70, 71, and 98 of the Code of the Federal Regulations 

is proposed to be amended as follows: 

PART 60--[AMENDED] 

1. The authority citation for part 60 continues to read as 

follows: 

 Authority: 42 U.S.C. 7401, et seq. 

Subpart Da-—[Amended] 

2. Section 60.46Da is revised to read as follows: 

§60.46Da Standards for carbon dioxide (CO2) 

(a) Your electric utility steam generating unit or IGCC 

electric utility steam generating unit is subject to this 

section if construction commenced on or after [INSERT DATE OF 

PUBLICATION IN THE FEDERAL REGISTER], and the affected facility 

meets the conditions specified in paragraph (1) and (2) of this 

subsection, except as specified in paragraph (b) of this 

section. 

(1) The affected facility burns fossil fuel for more than 

10.0 percent of the average annual heat input during any 3 

consecutive calendar years. 

(2) The affected facility supplies more than one-third of 

its potential electric output and more than 219,000 MWh net-
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electrical output to a utility power distribution system for 

sale. 

(b) The following EGUs are not subject to this section: 

(1) The proposed Wolverine EGU project described in Permit 

to Install No. 317-07 issued by the Michigan Department of 

Environmental Quality, Air Quality Division, effective June 29, 

2011 (as revised July 12, 2011). 

(2) The proposed Washington County EGU project described in 

Air Quality Permit No. 4911-303-0051-P-01-0 issued by the 

Georgia Department of Natural Resources, Environmental 

Protection Division, Air Protection Branch, effective April 8, 

2010, provided that a complete request for an applicability 

determination for the project has been submitted to [INSERT 

APPROPRIATE EPA CONTACT INFORMATION] no later than 120 days 

after [INSERT DATE OF FEDERAL REGISTER PUBLICATION] and EPA 

determines that construction had not commenced for NSPS purposes 

as of [INSERT DATE OF PUBLICATION FOR 111(a)(2) PURPOSES]. 

(3) The proposed Holcomb EGU project described in Air 

Emission Source Construction Permit 0550023 issued by the Kansas 

Department of Health and Environment, Division of Environment, 

effective December 16, 2010, provided that a complete request 

for an applicability determination for the project has been 

submitted to [INSERT APPROPRIATE EPA CONTACT INFORMATION] no 

later than 120 days after [INSERT DATE OF FEDERAL REGISTER 
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PUBLICATION] and EPA determines that construction had not 

commenced for NSPS purposes as of [INSERT DATE OF PUBLICATION 

FOR 111(a)(2) PURPOSES]. 

(c) No owner or operator of an affected facility subject to 

this section shall cause to be discharged into the atmosphere 

from the affected facility any gases that contain CO2 in excess 

of the emissions limitation specified in either paragraph (1) or 

(2) of this subsection. 

(1) 450 kilograms (kg) of CO2 per megawatt-hour (MWh) of 

gross energy output (1,000 lb CO2/MWh) on a 12-operating month 

rolling average basis;or 

(2) 480 kg of CO2 per MWh of gross energy output (1,050 lb 

CO2/MWh) on a 60-operating month rolling average basis. 

(d) Your affected facility must be in compliance at all 

times with the applicable CO2 emission limitation in paragraph 

(c) of this section for which you have elected to comply. 

However, compliance determinations are only to be made at the 

end of each operating month, as provided in paragraphs (1) and 

(2) of this subsection. For the purpose of this section, 

operating month means a calendar month during which any fuel is 

combusted in an affected facility at any time. 

(1) If you elect to comply with the CO2 emissions limitation 

in paragraph (c)(1) of this section, you must determine 
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compliance monthly by calculating the average CO2 emissions rate 

for the affected facility at the end of each preceding 12-

operating month period. 

(2) If you elect to comply with the CO2 emissions limitation 

in paragraph (c)(2) of this section, you must determine 

compliance monthly by calculating the average CO2 emissions rate 

for the affected facility at the end of each preceding 60-

operating month period. 

(e) You must conduct an initial CO2 emissions limitation 

determination for your affected facility within 30 days after 

the required number of operating months for the CO2 emission 

limitation operating month compliance period that you have 

elected to comply with have been accumulated (i.e., 12-operating 

months or 60-operating months. The first operating month 

included in this compliance period is the month in which 

emissions reporting is required to begin under §75.64(a) of this 

chapter. 

(f) You must monitor and collect data to demonstrate 

compliance with the CO2 emissions limitation according to the 

requirements specified in paragraphs (f)(1) through (4) of this 

section. 

(1) You must prepare a monitoring plan in accordance with 

the applicable provisions in §§75.53(g) and (h) of this chapter. 
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(2) You must measure the hourly CO2 mass emissions from each 

affected facility using the procedures specified in paragraphs 

(f)(2)(i) through (vii) of this section, except as provided in 

paragraph (3) of this section. 

(i) You must install, certify, operate, maintain, and 

calibrate a CO2 continuous emission monitoring system (CEMS) to 

directly measure and record CO2 concentrations in the exhaust 

gases from your affected facility that are vented to the 

atmosphere and an exhaust gas flow rate monitoring system 

according to §75.10(a)(3)(i) of this chapter. If CO2

concentration is measured on a dry basis, you must also install, 

certify, operate, maintain, and calibrate a continuous moisture 

monitoring system, according to §75.11(b) of this chapter. 

(ii) For each monitoring system used to determine the CO2

mass emissions, you must meet the applicable certification and 

quality assurance procedures in §75.20 of this chapter and 

appendices B and D to part 75 of this chapter. 

(iii) You must use a laser device to measure each exhaust 

gas stack or duct dimensions at the flow monitor and the 

reference method sampling locations prior to the initial setup 

(characterization) of the flow monitor. For circular stacks, 

make three determinations of the diameter and average the 

results. For rectangular stacks or ducts, make three 
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measurements of each dimension (i.e., depth and width) and 

average the results. If the flow rate monitor or reference 

method sampling site is relocated, repeat these measurements at 

the new location. 

(iv) Only unadjusted exhaust gas volumetric flow rates can 

be used to determine the hourly CO2 mass emissions from the 

affected facility; the bias adjustment factors described in 

Section 7.6.5 of Appendix A to part 75 of this chapter cannot be 

applied to the exhaust gas flow rate data. 

(v) If you elect to use Method 2 in Appendix A-1 to this 

part to perform the required relative accuracy test audits 

(RATAs) of the part 75 flow rate monitoring system, you must use 

a calibrated Type-S pitot tube or pitot tube assembly. Use of 

the default Type-S pitot tube coefficient is not permitted. 

(vi) If two or more affected facilities share a common 

exhaust gas stack and are subject to the same CO2 emissions 

limitation in paragraph (c) of this section, you may monitor the 

hourly CO2 mass emissions at the common exhaust gas stack in 

place of monitoring each affected facility separately. 

(vii) If the exhaust gases from the affected facilities are 

vented to the atmosphere through multiple stacks (or if the 

exhaust gases are routed to a common stack through multiple 

ducts and you elect to monitor in the ducts), you must monitor 
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the hourly CO2 mass emissions and the “stack operating time” (as 

defined in §72.2 of this chapter) at each stack or duct 

separately. 

 (3) You must install, calibrate, maintain, and operate a 

sufficient number of watt meters to continuously measure and 

record the gross electrical output from the affected facility, 

and must meet the requirements specified in paragraphs (f)(4)(i) 

and (ii) of this section, as applicable. 

(i) If your affected facility is a combined heat and power 

unit as defined in §60.42Da of this subpart, you must also 

install, calibrate, maintain, and operate meters to continuously 

determine and record the total useful recovered thermal energy. 

For process steam applications, this information includes steam 

flow rate, temperature, and pressure. If the combined heat and 

power unit has a direct mechanical drive application, you must 

submit a plan to the Administrator or delegated authority for 

approval of how gross energy output will be determined. 

(ii) If two or more affected facilities’ steam generating 

units serve a common electrical generator, you must apportion 

the combined hourly gross electrical output to each individual 

affected facility using a plan approved by the Administrator 

(e.g., using steam load or heat input to each affected 

facility). 
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(g) You must demonstrate compliance with the CO2 emissions 

limitation using the procedures specified in paragraphs (g)(1) 

and (2) of this section. 

(1) You must calculate the CO2 mass emissions output-based 

rate for your affected facility using the hourly CO2 mass 

emissions and gross energy output data determined and recorded 

according to the procedures specified in paragraph (f) of this 

section for each operating hour in the applicable operating 

month compliance period for the CO2 emissions limitation (i.e., 

12-operating months or 60-operating months), and the calculation 

procedures specified in paragraphs (g)(1)(i) through (v) of this 

section. 

(i) Use only operating hours in the operating month 

compliance period for which quality-assured data are obtained 

for all parameters used to determine the hourly CO2 mass 

emissions. No operating hours in which the substitute data 

provisions of part 75 of this chapter are used for any of those 

parameters are to be included in the calculation. For the 

compliance determination calculation, you must obtain “valid” 

hourly CO2 mass emission values for a minimum of 95 percent of 

the operating hours in the operating month compliance period for 

the CO2 emissions limitation applicable to the affected facility. 
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(ii) Calculate the total CO2 mass emissions by summing all 

of the valid hourly CO2 mass emissions values determined for the 

applicable operating month compliance period interval. In a case 

for which exhaust gases from the affected facility are vented to 

the atmosphere through multiple stacks or ducts, the total CO2

mass emissions for the affected facility is calculated by 

summing the total CO2 mass emissions determined from each of the 

individual stacks or ducts. 

(iii) For each operating hour of the operating month 

compliance period used in paragraph (g)(1)(ii) of this section 

to calculate the total CO2 mass emissions, determine the affected 

facility’s corresponding hourly gross energy output using the 

appropriate definition in §60.42Da of this subpart for your 

affected facility. For an operating hour in which there is no 

gross electrical load, but there is mechanical or useful thermal 

output, you must still determine the gross energy output for 

that hour. In the case for which hourly CO2 mass emissions are 

determined for a common stack, then the hourly gross energy 

output (electrical, thermal, and/or mechanical, as applicable) 

is determined by summing the hourly loads for the individual 

affected facility and the operating time is expressed as “stack 

operating hours” (as defined in §72.2 of this chapter). 
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(iv) Calculate the total gross energy output by summing the 

hourly gross energy output values for the affected facility 

determined from paragraph (g)(1)(iii) of this section for all of 

the operating hours in the applicable operating month compliance 

period interval. 

(v) Calculate the CO2 mass emissions output-based rate for 

the applicable operating month compliance period interval by 

dividing the total CO2 mass emissions value from paragraph 

(g)(1)(ii) of this section by the total gross energy output 

value from paragraph (g)(1)(iv) of this section. 

(2) Compliance with the CO2 emissions limitation in 

paragraph (c) of this section is determined as specified in 

paragraphs (g)(2)(i) and (ii) of this section using the CO2 mass 

emissions output-based rate for your affected facility 

determined in paragraph (g)(1) of this section. 

(i) If the CO2 mass emissions output-based rate for the 

affected facility is less than or equal to the CO2 emissions 

limitation in paragraph (c) of this section applicable to your 

affected facility, then the affected facility is determined to 

be in compliance with the CO2 emissions limitation. If compliance 

with the CO2 emissions limitation is attained at a common stack 

for two or more affected facilities subject to the same CO2
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emissions limitation, each affected facility sharing the stack 

is considered to be in compliance. 

(ii) If the CO2 mass emissions output-based rate for the 

affected facility is greater than the CO2 emissions limitation in 

paragraph (c) of this section applicable to your affected 

facility, then the affected facility is determined to have 

excess emissions. 

(h) You must prepare and submit notifications and reports 

according to paragraphs (h)(1) through (4) of this section. 

(1) You must prepare and submit the notifications specified 

in §§60.7(a)(1) and (a)(3) and §60.19 of this part, as 

applicable to your affected facility. 

(2) You must prepare and submit notifications specified in 

§75.61 of this chapter, as applicable to your affected facility. 

(3) You must submit electronic quarterly reports according 

to the requirements specified in paragraphs (h)(3)(i) through 

(iii) of this section. 

(i) Initially, after the required number of operating 

months for the CO2 emission limitation operating month compliance 

period that you have elected to comply with have been 

accumulated (i.e., 12-operating months or 60-operating months), 

a report for the calendar quarter that includes the twelfth (or 

sixtieth) operating month must be submitted no later than 30 
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days after the end of that quarter. Thereafter, a report for 

each subsequent calendar quarter must be submitted no later than 

30 days after the end of the quarter. 

(ii) Each quarterly report must include the information 

specified in paragraphs (h)(3)(ii)(A) though (E) of this 

section. 

(A) Identification of the CO2 emission limitation operating 

month compliance period you have elected to comply. 

(B) Identification of any months in the calendar quarter 

that are not operating months. 

(C) For each operating month in the calendar quarter, the 

corresponding average CO2 mass emissions output-based rate for 

the applicable operating month compliance period interval, as 

determined according to paragraph (g) of this section. 

(D) Percentage of valid CO2 mass emission rates in each 

operating month compliance period (i.e., the total number of 

valid CO2 mass emission rates in that period divided by the total 

number of operating hours in that period, multiplied by 100 

percent). 

(E) Identification of any operating months in the calendar 

quarter with excess CO2 emissions. 

(iii) The final quarterly report of each calendar year must 

contain the following: 
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(A) Gross electric output sold to an electric grid over the 

4 quarters of the calendar year; and 

(B) The potential electric output of the facility. 

(iv) Each electronic report must be submitted using the 

Emissions Collection and Monitoring Plan System (ECMPS) Client 

Tool provided by the Clean Air Markets Division in the EPA 

Office of Atmospheric Programs. 

(4) You must meet all applicable reporting requirements and 

submit reports as required under subpart G of part 75 of this 

chapter. 

(i) For each affected electric utility stream generating 

unit, you must maintain records according to paragraphs (i)(1) 

through (8) of this section. 

(1) You must comply with the applicable recordkeeping 

requirements and maintain records as required under subpart F of 

part 75 of this chapter. 

(2) You must maintain records of the calculations performed 

to determine the total CO2 mass emissions for each operating 

month, and averages for each operating month compliance period 

interval (i.e., 12-operating months or 60-operating months, as 

applicable to the CO2 emissions limitations). 
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(3) You must maintain records of the applicable data 

recorded and calculations performed used to determine the gross 

energy output for each operating month. 

(4) You must maintain records of the calculations performed 

to determine the percentage of valid CO2 mass emission rates in 

each operating month compliance period. 

(5) You must maintain records of the calculations performed 

to assess compliance with each applicable CO2 emissions 

limitation in paragraph (c) of this section. 

(6) Your records must be in a form suitable and readily 

available for expeditious review. 

(7) You must maintain each record for 5 years following the 

date of each occurrence, measurement, maintenance, corrective 

action, report, or record except those records required to 

demonstrate compliance with a 60-operating month compliance 

period. You must maintain records required to demonstrate 

compliance with a 60-operating month compliance period for at 

least 10 years following the date of each occurrence, 

measurement, maintenance, corrective action, report, or record. 

(8) You must maintain each record on site for at least 2 

years after the date of each occurrence, measurement, 

maintenance, corrective action, report, or record, according to 
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§60.7. You may maintain the records off site and electronically 

for the remaining year(s) as required by this subpart. 

(j) PSD and Thresholds for Greenhouse Gases. 

(1) For purposes of 40 CFR 51.166(b)(49)(ii), with 

respect to GHG emissions from new EGUs, the “pollutant that 

is subject to the standard promulgated under section 111 of 

the Act” shall be considered to be the pollutant that 

otherwise is subject to regulation under the Act as defined 

in 40 CFR 51.166(b)(48) and in any SIP approved by the EPA 

that is interpreted to incorporate, or specifically 

incorporates, 40 CFR 51.166(b)(48). 

(2) For purposes of 40 CFR 52.21(b)(50)(ii), with 

respect to GHG emissions from new EGUs, the “pollutant that 

is subject to the standard promulgated under section 111 of 

the Act” shall be considered to be the pollutant that 

otherwise is subject to regulation under the Act as defined 

in 40 CFR 52.21(b)(49). 

(3) For purposes of 40 CFR 70.2, with respect to greenhouse 

gas emissions from new electric utility generating units, the 

“pollutant that is subject to any standard promulgated under 

section 111 of the Act” shall be considered to be the pollutant 

that otherwise is "subject to regulation" as defined in 40 CFR 

70.2. 
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(4) For purposes of 40 CFR 71.2, with respect to 

greenhouse gas emissions from new electric utility 

generating units, the “pollutant that is subject to any 

standard promulgated under section 111 of the Act” shall be 

considered to be the pollutant that otherwise is "subject 

to regulation" as defined in 40 CFR 71.2. 

(k) For purposes of this section, the following definitions 

apply: 

Gross energy output means:

(1) For electric utility steam generating units constructed, 

reconstructed, or modified after May 3, 2011, the gross 

electrical or mechanical output from the affected facility minus 

any electricity used to power the feedwater pumps plus 75 

percent of the useful thermal output measured relative to ISO 

conditions that is not used to generate additional electrical or 

mechanical output or to enhance the performance of the unit 

(i.e., steam delivered to an industrial process); 

(2) For combined heat and power facilities constructed, 

reconstructed, or modified after May 3, 2011, where at least 

20.0 percent of the total gross useful energy output consists of 

electric or direct mechanical output and 20.0 percent of the 

total gross useful energy output consists of thermal output, the 

gross electrical or mechanical output from the affected facility 
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divided by 0.95 minus any electricity used to power the 

feedwater pumps plus 75 percent of the useful thermal output 

measured relative to ISO conditions that is not used to generate 

additional electrical or mechanical output or to enhance the 

performance of the unit ( i.e., steam delivered to an industrial 

process); 

(3) For a IGCC electric utility generating unit constructed, 

reconstructed, or modified after May 3, 2011, the gross useful 

work performed is the gross electrical or mechanical output from 

the unit plus 75 percent of the useful thermal output measured 

relative to ISO conditions that is not used to generate 

additional electrical or mechanical output or to enhance the 

performance of the unit ( i.e., steam delivered to an industrial 

process). 

Integrated gasification combined cycle electric utility steam 

generating unit or IGCC electric utility steam generating unit

means an electric utility combined cycle gas turbine that is 

designed to burn fuels containing 50 percent (by heat input) or 

more solid-derived fuel not meeting the definition of natural 

gas plus any integrated equipment that provides electricity or 

useful thermal output to either the turbine engine and heat 

recovery steam generator or to power auxiliary equipment.. The 
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Administrator may waive the 50 percent solid-derived fuel 

requirement during periods of the gasification system 

construction, startup and commissioning, shutdown, or repair. No 

solid fuel is directly burned in the unit during operation. 

Net-electric output means 

(1) the gross electric sales to the utility power distribution 

system minus purchased power on a calendar year basis, or 

(2) For combined heat and power facilities where at least 20.0 

percent of the total gross useful energy output consists of 

electric or direct mechanical output and 20.0 percent of the 

total gross useful energy output consists of thermal output, 

net-electric output means the gross electric sales to the 

utility power distribution system minus purchased power of the 

thermal host facilities or facilities on a calendar year basis. 

Potential electrical output capacity means 33 percent or the 

design net electric output efficiency time the maximum design 

heat input capacity of the steam generating unit, divided by 

3,413 Btu/KWh, divided by 1,000 kWh/MWh, and multiplied by 8,760 

hr/yr (e.g. , a 35 percent efficient steam generating unit with 

a 100 MW (341 MMBtu/h) fossil-fuel heat input capacity would 

have a 306,420 MWh 12 month potential electrical output 

capacity). For electric utility combined cycle gas turbines the 

potential electrical output capacity is determined on the basis 
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of the fossil-fuel firing capacity of the steam generator 

exclusive of the heat input and electrical power contribution by 

the gas turbine. 

Steam generating unit for facilities constructed, 

reconstructed, or modified before May 4, 2011, means any 

furnace, boiler, or other device used for combusting fuel 

for the purpose of producing steam (including fossil-fuelfired steam generators associated with combined cycle gas 

turbines; nuclear steam generators are not included). For 

units constructed, reconstructed, or modified after May 3, 

2011, steam generating unit means any furnace, boiler, or 

other device used for combusting fuel for the purpose of 

producing steam (including fossil-fuel-fired steam 

generators associated with combined cycle gas turbines; 

nuclear steam generators are not included) plus any 

integrated equipment that provides electricity or useful 

thermal output to either the boiler or to power auxiliary 

equipment. 

* * * * * 

Subpart KKKK-—[Amended] 

 3. Section 60.4315 is revised to read as follows: 

§60.4315 What pollutants are regulated by this subpart? 

(a) The pollutants regulated by this subpart are nitrogen 
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oxides (NOX), sulfur dioxide (SO2), and greenhouse gas. 

(b)(1) The greenhouse gas regulated by this subpart is 

carbon dioxide (CO2). 

(2) PSD and Thresholds for Greenhouse Gases. 

(i) For purposes of 40 CFR 51.166(b)(49)(ii), with 

respect to GHG emissions from new EGUs, the “pollutant that 

is subject to the standard promulgated under section 111 of 

the Act” shall be considered to be the pollutant that 

otherwise is subject to regulation under the Act as defined 

in 40 CFR 51.166(b)(48) and in any SIP approved by the EPA 

that is interpreted to incorporate, or specifically 

incorporates, 40 CFR 51.166(b)(48). 

(ii) For purposes of 40 CFR 52.21(b)(50)(ii), with 

respect to GHG emissions from new EGUs, the “pollutant that 

is subject to the standard promulgated under section 111 of 

the Act” shall be considered to be the pollutant that 

otherwise is subject to regulation under the Act as defined 

in 40 CFR 52.21(b)(49). 

(iii) For purposes of 40 CFR 70.2, with respect to 

greenhouse gas emissions from new electric utility generating 

units, the “pollutant that is subject to any standard 

promulgated under section 111 of the Act” shall be considered to 

be the pollutant that otherwise is "subject to regulation" as 

defined in 40 CFR 70.2. 
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(iv) For purposes of 40 CFR 71.2, with respect to 

greenhouse gas emissions from new electric utility generating 

units, the “pollutant that is subject to any standard 

promulgated under section 111 of the Act” shall be considered to 

be the pollutant that otherwise is "subject to regulation" as 

defined in 40 CFR 71.2. 

4. Section 60.4325 is added to read as follows: 

§60.4325 What CO2 emissions standard must I meet? 

For each affected EGU subject to this subpart, you must not 

discharge from the EGU into the atmosphere any gases that 

contain CO2 in excess of the applicable CO2 emissions standard 

specified in Table 2 to this subpart. Each CO2 emissions standard 

has a minimum of two significant digits. 

5. Section 60.4333 is amended by adding paragraph (g) to 

read as follows: 

§60.4333 What are my general requirements for complying with 

this subpart? 

* * * * * 

(g) If you own or operate a stationary combustion turbine 

subject to a CO2 emissions standard in §60.4325, compliance 

determinations are to be made on a 12-operating month rolling 

average, you must determine compliance monthly by calculating 

the average CO2 emissions rate for the affected EGU at the end of 
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each preceding 12-operating month period. 

6. Section 60.4373 is added to read as follows: 

§60.4373 How do I monitor and collect data to demonstrate 

compliance with my CO2 emissions standard using a CO2 CEMS? 

(a) You must prepare a monitoring plan in accordance with 

the applicable provisions in §§75.53(g) and (h) of this chapter. 

(b) You must measure the hourly CO2 mass emissions from each 

affected EGU using the procedures specified in paragraphs (b)(1) 

through (5) of this section, except as provided in paragraph (c) 

of this section. 

(1) You must install, certify, operate, maintain, and 

calibrate a CO2 continuous emission monitoring system (CEMS) to 

directly measure and record CO2 concentrations in the EGU exhaust 

gases vented to the atmosphere and an exhaust gas flow rate 

monitoring system according to §75.10(a)(3)(i) of this chapter. 

If CO2 concentration is measured on a dry basis, you must also 

install, certify, operate, maintain, and calibrate a continuous 

moisture monitoring system, according to §75.11(b) of this 

chapter. 

(2) For each monitoring system used to determine the CO2

mass emissions, you must meet the applicable certification and 

quality assurance procedures in §75.20 of this chapter and 

appendices B and D to part 75 of this chapter. 
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(3) You must use a laser device to measure each exhaust gas 

stack or duct dimensions at the flow monitor and the reference 

method sampling locations prior to the initial setup 

(characterization) of the flow monitor. For circular stacks, 

make three determinations of the diameter and average the 

results. For rectangular stacks or ducts, make three 

measurements of each dimension (i.e., depth and width) and 

average the results. If the flow rate monitor or reference 

method sampling site is relocated, repeat these measurements at 

the new location. 

(4) Only unadjusted exhaust gas volumetric flow rates can 

be used to determine the hourly CO2 mass emissions from the 

affected EGU; the bias adjustment factors described in Section 

7.6.5 of Appendix A to part 75 of this chapter cannot be applied 

to the exhaust gas flow rate data. 

(5) If you elect to use Method 2 in Appendix A-1 to this 

part to perform the required relative accuracy test audits 

(RATAs) of the part 75 flow rate monitoring system, you must use 

a calibrated Type-S pitot tube or pitot tube assembly. Use of 

the default Type-S pitot tube coefficient is not permitted. 

(c) As an alternative to complying with paragraph (b) of 

this section, you may determine the hourly CO2 mass emissions by 

using Equation G-4 in appendix G to part 75 of this chapter 

according to the requirements specified in paragraphs (c)(1) and 
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(2) of this section. 

(1) You must implement the applicable procedures in 

appendix D to part 75 of this chapter to determine hourly unit 

heat input rates (MMBtu/h), based on hourly measurements of fuel 

flow rate and periodic determinations of the gross calorific 

value (GCV) of each fuel combusted. 

(2) You may determine site-specific carbon-based F-factors 

using Equation F-7b in section 3.3.6 of appendix F to part 75 of 

this chapter, and you may use these Fc values in the emissions 

calculations instead of using the default Fc values in the 

Equation G-4 nomenclature. 

(d) You must install, calibrate, maintain, and operate watt 

meter (and meters) to continuously measure and record the gross 

electrical output from the affected EGU. If the affected EGU is 

a CHP EGU, you must also install, calibrate, maintain, and 

operate meters to continuously determine and record the total 

useful recovered thermal energy. For steam this information 

includes flow rate, temperature, and pressure. If the CHP EGU 

has a direct mechanical drive application, you must submit a 

plan to the Administrator or delegated authority for approval of 

how gross energy output will be determined. 

(e) If two or more affected EGUs serve a common electrical 

generator, you must apportion the combined hourly gross output 

to the individual EGUs using a plan approved by the 
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Administrator (e.g., using steam load or heat input to each 

affected EGU). 

(f) In accordance with §60.13(g), if two or more EGUs that 

implement the continuous emission monitoring provisions in 

paragraph (b) of this section share a common exhaust gas stack 

and are subject to the same emissions standard under §60.4325, 

you may monitor the hourly CO2 mass emissions at the common stack 

in lieu of monitoring each EGU separately. If this option is 

chosen, the hourly gross load (electrical, thermal, and/or 

mechanical, as applicable) shall be the sum of the hourly loads 

for the individual EGUs and the operating time shall be 

expressed as “stack operating hours” (as defined in §72.2 of 

this chapter). If compliance with the applicable emissions 

standard in §60.4325 is attained at the common stack, each EGU 

sharing the stack is considered to be in compliance. 

(g) In accordance with §60.13(g), if the exhaust gases from 

an EGU that implements the continuous emission monitoring 

provisions in paragraph (b) of this section are vented to the 

atmosphere through multiple stacks (or if the exhaust gases are 

routed to a common stack through multiple ducts and you elect to 

monitor in the ducts), you must monitor the hourly CO2 mass 

emissions and the “stack operating time” (as defined in §72.2 of 

this chapter) at each stack or duct separately. In this case, 

compliance with the applicable emissions standard in §60.4325 is 
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determined by summing the CO2 mass emissions measured at the 

individual stacks or ducts and dividing by the total gross 

output for the unit. 

7. Section 60.4374 is added to read as follows: 

§60.4374 How do I demonstrate compliance with my CO2 emissions 

standard and determine excess emissions? 

(a) You must calculate the CO2 mass emissions output-based 

rate for your affected EGU by using the hourly CO2 mass emissions 

and total gross output data determined and recorded according to 

the procedures specified in §60.4373 for each operating hour in 

the applicable operating month compliance period for the CO2

emissions standard applicable to the affected EGU, and the 

calculation procedures specified in paragraphs (a)(1) through 

(a)(5) of this section. 

(1) Only operating hours in the operating month compliance 

period are used for the compliance determination calculation for 

which quality-assured data are obtained for all parameters used 

to determine the hourly CO2 mass emissions. No operating hours in 

which the substitute data provisions of part 75 of this chapter 

are used for any of those parameters are to be included in the 

calculation. For the compliance determination calculation, you 

must obtain “valid” hourly CO2 mass emission values for a minimum 

of 95 percent of the operating hours in the operating month 
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compliance period for the CO2 emissions standard applicable to 

the affected EGU. 

(2) Calculate the total CO2 mass emissions for the affected 

EGU’s operating month compliance period by summing the hourly CO2

mass emissions values for the affected EGU determined to be 

valid according to the conditions specified in paragraph (a)(1) 

of this section for all of the operating hours in the applicable 

operating month compliance period. 

(3) For each operating hour of the operating month 

compliance period used in paragraph (a)(2) of this section to 

calculate the total CO2 mass emissions, determine the affected 

EGU’s corresponding hourly gross output according to the 

procedures specified in paragraphs (a)(3)(i) and (ii) of this 

section, as appropriate for the type of stationary combustion 

turbine or steam generating unit used for the EGU. For an 

operating hour in which there is no gross electrical load, but 

there is mechanical or useful thermal output, you must still 

determine the gross output for that hour. 

(i) The gross output of a stationary combustion turbine 

with respect to CO2 emissions is determined as specified in 

paragraphs (a)(3)(i)(A) and (B) of this section. 

(A) The gross electrical and mechanical output from the 

stationary combustion turbine plus 75 percent of the useful 

thermal output measured relative to ISO conditions that is not 
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used to generate additional electrical or mechanical output or 

to enhance the performance of the unit (e.g., steam delivered to 

an industrial process); or 

(B) For a CHP EGU where at least 20.0 percent of the total 

gross useful energy output consists of electric or direct 

mechanical output and 20.0 percent of the total gross useful 

energy output consists of useful thermal output on an three 

calendar year rolling average basis, the gross electrical and 

mechanical output from the stationary combustion turbine 

facility divided by 0.95 plus 75 percent of the useful thermal 

output measured relative to ISO conditions that is not used to 

generate additional electrical or mechanical output or to 

enhance the performance of the unit (i.e., steam delivered to an 

industrial process). 

(ii) Gross output of a steam generating unit with respect 

to CO2 emissions is determined as specified in paragraphs 

(a)(3)(ii)(A) and (B) of this section. 

(A) The gross electrical and mechanical output from the 

steam generating unit minus any electricity used to power the 

feedwater pumps plus 75 percent of the useful thermal output 

measured relative to ISO conditions that is not used to generate 

additional electrical or mechanical output or to enhance the 

performance of the unit (e.g., steam delivered to an industrial 

process); or 
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(B) For a CHP EGU where at least 20.0 percent of the total 

gross useful energy output consists of electric or direct 

mechanical output and 20.0 percent of the total gross useful 

energy output consists of useful thermal output on an three 

calendar year rolling average basis, the difference of gross 

electrical and mechanical output from the affected steam 

generating unit minus any electricity used to power the 

feedwater pumps divided by 0.95 plus 75 percent of the useful 

thermal output measured relative to ISO conditions that is not 

used to generate additional electrical or mechanical output or 

to enhance the performance of the unit (i.e., steam delivered to 

an industrial process). 

(4) Calculate the total gross output for the affected EGU’s 

compliance period by summing the hourly gross output values for 

the affected EGU determined from paragraph (a)(2) of this 

section for all of the operating hours in the applicable 

compliance period. 

(5) Calculate the CO2 mass emissions output-based rate for 

the affected EGU by dividing the total CO2 mass emissions value 

from paragraph (a)(2) of this section by the total gross output 

value from paragraph (a)(4) of this section. 

(b) If the CO2 mass emissions output-based rate for the 

affected EGU determined according to the procedures specified in 

paragraph (a) of this section is less than or equal to the CO2 
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emissions standard in Table 2 of this subpart applicable to the 

EGU, then the affected EGU is determined to be in compliance 

with the emissions standard. If the average CO2 mass emissions 

rate is greater than the CO2 emissions standard in Table 2 of 

this subpart applicable to the EGU, then the affected EGU is 

determined to have excess emissions. 

8. Section 60.4375 is amended by revising the section 

heading to read as follows: 

§60.4375 What reports must I submit to comply with my NOx and SO2

emissions limits? 

* * * * * 

9. Section 60.4376 is added to read as follows: 

§60.4376 What notifications and reports must I submit to comply 

with my CO2 emissions standard? 

(a)(1) You must prepare and submit the notifications 

specified in §§60.7(a)(1) and (a)(3) and §60.19, as applicable 

to your affected EGU. 

(2) You must prepare and submit notifications specified in 

§75.61 of this chapter, as applicable to your affected EGU. 

(b) You must prepare and submit reports according to 

paragraphs (b) through (d) of this section, as applicable. 

(1) For EGUs that are required, pursuant to §§60.4333 (g), 
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to conduct initial and on-going compliance determinations on a 

12-operating month rolling average basis with respect to the 

standard in §60.4325 you must submit electronic quarterly 

reports as follows. After the first 12-operating months have 

been accumulated for the EGU, a report for the calendar quarter 

that includes the twelfth operating month shall be submitted no 

later than 30 days after the end of that quarter. Thereafter, a 

report for each subsequent calendar quarter shall be submitted, 

no later than 30 days after the end of the quarter. 

(2) Each quarterly report shall include the following 

information, as applicable: 

(i) Each rolling average CO2 mass emissions rate for which 

the last (twelfth) operating month in a 12-operating month 

compliance period falls within the calendar quarter. Calculate 

each average CO2 mass emissions rate according to §§60.4374. 

Report the dates (month and year) of the first and twelfth 

operating months in each compliance period for which a CO2 mass 

emissions rate calculation is performed. If there are no 

compliance periods that end in the quarter, include a statement 

to that effect; 

(ii) Identification of each operating month in the calendar 

quarter with excess CO2 emissions. If one or more compliance 

periods end in the quarter; 

(iii) The percentage of valid CO2 mass emission rates (as 
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defined in §60. 4374) in each 12-operating month compliance 

period described in paragraph (b)(1)(i) of this section (i.e., 

the total number of valid CO2 mass emission rates in that period 

divided by the total number of operating hours in that period, 

multiplied by 100 percent); and 

(iv) Indication of which compliance option is being 

followed under §60.4325. 

(3) The final quarterly report of each calendar year must 

contain the following: 

(i) Gross electric output sold to an electric grid over the 

4 quarters of the calendar year; and 

(ii) The potential electric output of the facility. 

(c) All electronic reports required under paragraph (b) of 

this section shall be submitted using the Emissions Collection 

and Monitoring Plan System (ECMPS) Client Tool provided by the 

Clean Air Markets Division in the Office of Atmospheric Programs 

of the EPA. 

(d) You must meet all applicable reporting requirements and 

submit reports as required under subpart G of part 75 of this 

chapter. 

10. Section 60.4390 is amended by revising the section 

heading to read as follows: 

§60.4390 What records must I maintain to comply with my NOx and 
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SO2 emissions limits? 

* * * * * 

11. Section 60.4391 is added to read as follows: 

§60.4391 What records must I maintain to comply with my CO2

emissions limits? 

 (a) You must maintain records of your information used to 

demonstrate compliance with this subpart as specified in §60.7 

(b) and (f). 

(b) You must follow the applicable recordkeeping 

requirements and maintain records as required under subpart F of 

part 75 of this chapter. 

(c) You must keep records of the calculations performed to 

determine the total CO2 mass emissions for: 

(1) Each operating month (for all affected units); 

(2) Each compliance period, including, as applicable, each 

12-operating month compliance period. 

(d) You must keep records of the applicable data recorded 

and calculations performed used to determine your affected EGU’s 

gross output for each operating month. 

(e) You must keep records of the calculations performed to 

determine the percentage of valid CO2 mass emission rates in each 

compliance period. 

(f) You must keep records of the calculations performed to 
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assess compliance with each applicable CO2 mass emissions 

standard in §60.4325. 

(g) You must keep records of the calculations performed to 

determine any site-specific carbon-based F-factors used in the 

emissions calculations (if applicable). 

(h)(1) Your records must be in a form suitable and readily 

available for expeditious review. 

(2) You must keep each record for 5 years following the 

date of each occurrence, measurement, maintenance, corrective 

action, report, or record to demonstrate compliance with a 12-

operating month emissions standard. 

(3) You must keep each record on site for at least 2 years 

after the date of each occurrence, measurement, maintenance, 

corrective action, report, or record, according to §60.7. You 

may keep the records off site and electronically for the 

remaining year(s) as required by this subpart. 

12. Section 60.4395 is amended to read as follows: 

§60.4395 When must I submit my reports? 

Consistent with §60.7(c), all reports required under 

§60.7(c) must be postmarked by the 30th day following the end of 

each 6-month period, except as specified in §60.4376 

13. Section 60.4421 is added to read as follows: 

§60.4421 What definitions with respect to CO2 emissions apply to 
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this subpart? 

Base load rating means 100 percent of the manufacturer's design 

heat input capacity of the combustion turbine engine at ISO 

conditions using the higher heating value of the fuel (heat 

input from duct burners is not included). 

Electric generating unit or EGU means any steam electric 

generating unit or stationary combustion turbine that generates 

electricity. 

Excess emissions means a specified averaging period over which 

either (1) the NOX, CO2 or SO2 emissions rate are higher than the 

applicable emissions standard in §60.4320, §60.4325 or 

§60.4330; (2) the total sulfur content of the fuel being 

combusted in the affected facility or the SO2 emissions exceeds 

the standard specified in §60.4330; or (3) the recorded value of 

a particular monitored parameter, including ration of water or 

steam to fuel, is outside the acceptable range specified in the 

parameter monitoring plan for the affected unit. 

Gross useful energy output means: 

(1) For simple cycle and combined cycle combustion turbines, the 

gross useful work performed is the gross electrical or direct 

mechanical output from both the combustion turbine engine and 

any associated steam turbine(s). 

(2) For a CHP combustion turbine, the gross useful work 
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performed is the gross electrical or direct mechanical output 

from both the combustion turbine engine and any associated steam 

turbine(s) plus any useful thermal output measured relative to 

ISO conditions (except for GHG calculations in §60.4374 as only 

75 percent credit is given) that is not used to generate 

additional electrical or mechanical output or to enhance the 

performance of the unit (i.e., steam delivered to an industrial 

process). 

Heat recovery steam generating unit (HRSG) means a unit where 

the hot exhaust gases from the combustion turbine engine are 

routed in order to extract heat from the gases and generate 

useful output. Heat recovery steam generating units can be used 

with or without duct burners. 

Integrated gasification combined cycle electric utility steam 

generating unit (IGCC) means an electric utility steam 

generating unit that burns solid-derived fuels in a combinedcycle combustion turbine plus any integrated equipment that 

provides electricity or useful thermal output to either the 

turbine engine and HRSG or to power auxiliary equipment. No 

solid fuel is directly combusted in the unit during operation. 

Net-electric output means: 
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(1) The gross electric sales to the utility power distribution 

system minus purchased power on a three calendar year rolling 

average basis; or 

(2) For combined heat and power facilities where at least 20.0 

percent of the total gross useful energy output consists of 

electric or direct mechanical output and 20.0 percent of the 

total gross useful energy output consists of useful thermal 

output on a 3 calendar year rolling average basis, net-electric 

output means the gross electric sales to the utility power 

distribution system minus purchased power of the thermal host 

facility or facilities on a three calendar year rolling average 

basis. 

Operating month means a calendar month during which any fuel is 

combusted in the EGU at any time. 

Potential electric output means 33 percent or the design 

electric output efficiency on a net output basis times the 

maximum design heat input capacity (expressed in MMBtu/h) of the 

steam generating unit, 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 EGU with a 100 MW (341 

MMBtu/h) fossil-fuel heat input capacity would have a 306,420 

MWh 12 month potential electrical output capacity). 

Stationary combustion turbine means all equipment, including but 

not limited to the combustion turbine engine, the fuel, air, 
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lubrication and exhaust gas systems, control systems, heat 

recovery system, steam turbine, fuel compressor, heater, and/or 

pump, post-combustion emission control technology, and any 

ancillary components and sub-components plus any integrated 

equipment that provides electricity or useful thermal output to 

either the boiler or to power auxiliary equipment. Stationary 

means that the combustion turbine is not self propelled or 

intended to be propelled while performing its function. It may, 

however, be mounted on a vehicle for portability. 

Steam generating unit means any furnace, boiler, or other device 

used for combusting fuel and producing steam (nuclear steam 

generators are not included) plus any integrated equipment that 

provides electricity or useful thermal output to either the 

boiler or to power auxiliary equipment. 

System emergency means any abnormal system condition that 

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. 

* * * * * 

14. Table 2 is added to read as follows: 

Table 2 to Subpart KKKK of Part 60 – EGU CO2 Emission Standards 

Affected EGU CO2 Emission Standard

Stationary combustion turbine 450 kilograms (kg) of CO2 per 
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that has a design heat input to 

the turbine engine of greater 

than 250 MW (850MMBtu/h), that 

burns fossil fuel for more than 

10.0 percent of the average 

annual heat input during a 3 

year rolling average basis, and 

supplies one-third or more of 

its potential electric output 

and more than 219,000 MWh netelectrical output to a utility 

distribution system on a 3 year 

rolling average basis. 

megawatt-hour (MWh) of gross 

output (1,000 lb/MWh) on a 12-

operating month rolling average 

Stationary combustion turbine 

that has a design heat input to 

the turbine engine equal to or 

less than 250 MW (850MMBtu/h), 

that burns fossil fuel for more 

than 10.0 percent of the 

average annual heat input 

during a 3 year rolling average 

basis, and that supplies onethird or more of its potential 

electric output and more than 

219,000 MWh net-electrical 

output to a utility 

distribution system on a 3 year 

rolling average basis. 

500 kg of CO2 per MWh of gross 

output (1,100 lb CO2/MWh) on a 

12-operating month rolling 

average 

15. Table 3 is added to reads as follows: 

Table 3 to Subpart KKKK of Part 60 – Applicability of Subpart A 

General Provisions to EGU CO2 Emissions Standards in Subpart KKKK 

General 

Provisions 

citation 

Subject of 

citation 

Applies to 

subpart 

KKKK 

Explanation 

§60.1 Applicability Yes 

§60.2 Definitions Yes 

Additional terms 

defined in 

§60.4420 
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§60.3 Units and 

Abbreviations Yes 

§60.4 Address Yes 

§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 

notification in 

60.7(a)(1) and 

(a)(3) 

§60.8 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 Yes 

§60.14 Modification No 

§60.15 Reconstruction No 

§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 
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PART 70—[AMENDED] 

16. The authority citation for part 70 continues to read as 

follows: 

Authority: 42 U.S.C. 7401 et seq. 

 17. Section 70.2 is amended by adding new paragraph (4) to 

the definition of “Regulated pollutants (for presumptive fee 

calculation)” to read as follows: 

§ 70.2 Definitions. 

* * * * * 

Regulated pollutant (for presumptive fee calculation), which is 

used only for purposes of § 70.9(b)(2), means any “regulated air 

pollutant” except the following: 

(1) Carbon monoxide; 

(2) Any pollutant that is a regulated air pollutant solely 

because it is a Class I or II substance to a standard 

promulgated under or established by title VI of the Act; or 

(3) Any pollutant that is a regulated air pollutant solely 

because it is subject to a standard or regulation under section 

112(r) of the Act; 

(4) Greenhouse gases. 

* * * * * 

 18. Section 70.9 is amended by revising paragraph 

(b)(2)(i), by adding a new paragraph (b)(2)(v)) to read as 

follows: 
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§ 70.9 Fee determination and certification. 

* * * * * 

(b) * * * 

 (2)(i) The Administrator will presume that the fee schedule 

meets the requirements of paragraph (b)(1) of this section if it 

would result in the collection and retention of an amount not 

less than $25 per year [as adjusted pursuant to the criteria set 

forth in paragraph (b)(2)(iv) of this section] times the total 

tons of the actual emissions of each regulated pollutant (for 

presumptive fee calculation) emitted from part 70 sources and 

the GHG cost adjustment required under paragraph (b)(2)(v) of 

this section. 

* * * * * 

(v) GHG cost adjustment. The amount calculated in 

paragraph (b)(2)(i) of this section shall be increased by the 

GHG cost adjustment determined as follows: For each activity 

identified in the following table, multiply the number of 

activities performed by the permitting authority by the burden 

hours per activity, and then calculate a total number of burden 

hours for all activities. Next, multiply the burden hours by the 

average cost of staff time, including wages, employee benefits 

and overhead. 

Activity Burden 
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hours 

per 

activity 

Preparing a permit application (add GHG to a 

non-GHG permit) 

Modification due to GHG 

Modification to address GHG in a non-GHG 

permit 

Address GHG at permit renewal 

43

40

9

4

* * * * * 

PART 71—[AMENDED] 

19. The authority citation for part 71 continues to read as 

follows: 

Authority: 42 U.S.C. 7401 et seq. 

20. Section 71.2 is proposed to be amended by adding new 

paragraph (4) to the definition of “Regulated pollutant (for fee 

calculation)” to read as follows:

§ 71.2 Definitions. 

* * * * * 

Regulated pollutant (for fee calculation), which is used only 

for purposes of § 71.9(c), means any “regulated air pollutant” 

except the following: 

(1) Carbon monoxide; 

(2) Any pollutant that is a regulated air pollutant solely 

because it is a Class I or II substance to a standard 

promulgated under or established by title VI of the Act; or 
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(3) Any pollutant that is a regulated air pollutant solely 

because it is subject to a standard or regulation under section 

112(r) of the Act; 

(4) Greenhouse gases. 

* * * * * 

 21. Section 71.9 is amended: 

 a. By revising paragraph ©(1), 

 b. By revising paragraph ©(2) 

c. By adding a new paragraph ©(8). 

 The additions read as follows: 

§ 71.9 Fee determination and certification. 

* * * * * 

(c) Establishment of fee schedule. 

(1) For part 71 programs that are administered by EPA, each 

part 71 source shall pay an annual fee which is the sum of: 

(i) $32 per ton (as adjusted pursuant to the criteria set 

forth in paragraph (n)(1) of this section) times the total tons 

of the actual emissions of each regulated pollutant (for fee 

calculation) emitted from the source, including fugitive 

emissions; and 

(ii) any GHG fee adjustment required under paragraph ©(8) 

of this section. 

(2) For part 71 programs that are fully delegated pursuant 

to § 71.10: 
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(i) Where the EPA has not suspended its part 71 fee 

collection pursuant to paragraph ©(2)(ii) of this section, the 

annual fee for each part 71 source shall be the sum of: 

(A) $24 per ton (as adjusted pursuant to the criteria set 

forth in paragraph (n)(1) of this section) times the total tons 

of the actual emissions of each regulated pollutant (for fee 

calculation) emitted from the source, including fugitive 

emissions; and 

(B) any GHG fee 45djusttment required under paragraph 

(c)(8) of this section. 

(ii) Where the delegate State collects fees from part 71 

sources under State law which are sufficient to fund the 

delegated part 71 program, the EPA may suspend its collection of 

part 71 fees. The specific terms and conditions regarding the 

suspension of fee collection will be addressed in the applicable 

delegation agreement pursuant to § 71.10. 

* * * * * 

(8) GHG fee adjustment. The annual fee shall be increased 

by a GHG fee adjustment for any source that has initiated an 

activity listed in the following table since the fee was last 

paid. The GHG fee adjustment shall be equal to the set fee 

provided in the table for each activity that has been initiated 

since the fee was last paid: 
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Activity Set fee 

Preparing a permit application (add GHG to a 

non-GHG permit) 

Modification due to GHG 

Modification to address GHG in a non-GHG 

permit 

Address GHG at permit renewal 

$2,236

$2,080

$468

$208

* * * * * 

PART 98—[AMENDED] 

22. The authority citation for part 98 continues to read as 

follows: 

Authority: 42 U.S.C. 7401-7671q. 

Subpart PP—[AMENDED] 

23. Section 98.426 is amended by adding paragraph (h) to 

read as follows: 

§98.426 Data reporting requirements.

* * * * * 

(h) If you capture a CO2 stream from an electricity 

generating unit that is subject to subpart D of this part and 

transfer CO2 to any facilities that are subject to subpart RR of 

this part, you must: 

(1) Report the facility identification number associated 

with the annual GHG report for the subpart D facility, 
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(2) Report each facility identification number associated 

with the annual GHG reports for each subpart RR facility to 

which CO2 is transferred, and 

(3) Report the annual quantity of CO2 in metric tons that 

is transferred to each subpart RR facility. 

24. Section 98.427 is amended by adding paragraph (d) to 

read as follows: 

§98.427 Records that must be retained.

 (d) Facilities subject to §98.426(h) must retain records of CO2

in metric tons that is transferred to each subpart RR facility.