From: Wayland, Robertj

To: Frey, Nathan J.

Cc: Culligan, Kevin; Tsirigotis, Peter; Hutson, Nick; Fellner, Christian

Subject: EPA Responses to Initial OMB/Interagency Comments

Date: Monday, August 19, 2013 4:50:21 PM

Attachments: Summary of Interagency Comments Under EO 12866 13563 EGU NSPS_2060_AQ91_....docx

Nathan –

Attached to this email is EPA’s response to the initial set of Interagency comments on the

EGU GHG NSPS proposal. As requested, we have provided our responses in writing in the

attached document. Once you and the interagency working group have had the

opportunity to review these responses, please let me know how you would like to proceed

as we move forward. If you have any questions, please feel free to contact me, Kevin, Nick

or Christian.

thanx!

bob

Robert J. Wayland, Ph.D.

Leader, Energy Strategies Group

U.S. Environmental Protection Agency

Office of Air Quality Planning and Standards

Sector Policies and Programs Division

Mail Code D243-01

Research Triangle Park, NC 27709

Office: (919) 541-1045

Cell: (919) 306-2290

Fax: (919) 541-5450

Email: wayland.robertj@epa.gov

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DRAFT/Deliberative Document - FOIA Exempt

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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.   

[EPA Response:  The EPA is still drafting the FR notice rescinding the April 2012 proposal.]

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

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

complementary to the rationale set forth in this proposal?

[EPA Response:  The EPA has considered (and continues to consider) the merits of the rationale

from the April 2012 proposal and how it may be complementary to the current proposal.  We do

intend to add language specifically soliciting comment on the potential benefits or merits of

placing all sources in a single subpart TTTT as was previously proposed.   With respect to the

issue of whether to rely on a fuel‐neutral justification for the standard – that is, identifying

natural gas combined cycle units as the “best system of emission reduction” for coal‐fired power

plants as an alternative to CCS – we have considered that issue and are prepared to discuss it

with the interagency group.

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

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

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

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

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

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

the law?

[EPA Response:  On June 25, 2013 President Obama issued the “Presidential Memorandum –

Power Sector Carbon Pollution Standards” directing the EPA to issue a new NSPS proposal by no

later than September 20, 2013 and to issue proposed carbon pollution standards, regulations or

guidelines, as appropriate, for modified, reconstructed and existing power plants by no later

than June 1, 2014. By statute, in order to issue emission standards for existing sources, the

Agency must first propose standards of performance for new sources.  Further, given that we

have made an endangerment finding for GHGs under title II, are regulating GHGs under title II,

and have interpreted PSD to apply to GHGs, issuing a NSPS for the largest stationary source of

CO2 is consistent with the policy objectives and rationale of 12866.]

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

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

companies to invest in technologies to further reduce emissions, unless there were external
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market forces that would prompt them to do so.  In which case, the regulation would not be

needed.  Can EPA explain this line of thinking further?

[EPA Response:  We believe that the regulatory certainty offered by this rule – which will

require new fossil fuel‐fired boilers and IGCC units to capture a fraction of the produced CO2 –

can incentivize further development of carbon capture technologies.  In contrast, an emission

limitation based on “best generating technology” would offer no clear incentive for additional

CCS research, development and demonstration (since such a standard would be met with no

need for CCS technology).  It has been suggested that an emission standard that required very

deep CO2 capture could also stifle continued research & development of the technology due to

the excessive costs. Further, the observed behavior and distinctive characteristics of the

industry raise the possibility that some firms may make non‐purely‐market‐driven investment

decisions.  One of the purposes of setting this standard is to ensure that those investments

include options that are directed at environmental innovation.]

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

commenced construction by publication?

[EPA Response: We are not exempting Wolverine from the proposed NSPS, rather we are

deferring making a determination of the appropriate standard until we have additional

information. A more comprehensive legal justification is provided in a Technical Support

Document entitled “Fossil Fuel‐Fired Boiler and IGCC EGU Projects Under Development: Status

and Approach” which will be provided to OMB/Interagency and placed in the rulemaking

docket.]

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

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

purposes of NSPS compliance?

[EPA Response:  Steam based EGUs that burn a combination of coal and natural gas would be

covered under subpart Da. On August 29, 2012 (77 FR 52554), the EPA proposed amendments

to the applicability of subpart KKKK such that all simple cycle, combined cycle, and combustion

turbine based combined heat and power facilities would be covered by subpart KKKK with two

exceptions. IGCC facilities would be covered by subpart Da and heat recovery steam generators

that burn solid fuels or that use oxygen beyond what is included in the turbine engine exhaust

(the use of additional combustion air) would be subject to the applicable steam generating unit

(boiler) NSPS based on the size of the duct burners. In addition, the definition of an affected

facility in this proposed rule include “integrated equipment that provides electricity or useful

thermal output to either the boiler (or turbine engine and heat recovery steam generator in the

case of an IGCC) or to power auxiliary equipment.” Under this proposed approach, combustion

turbines that enhance the performance of steam plants through feedwater heating, providing

steam directly to the steam cycle, or use of the combustion turbine exhaust as preheated air for

the boiler of the steam turbine unit would be considered part of the subpart Da affected

facility.]
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Best System of Emission Reduction (BSER):

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

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

combustion).

[EPA Response:  The EPA does not prescribe the use of any specific technology to meet the

emission limitation. The EPA does base the emission limitation on the performance of the best

system of emission reduction – but sources are not required to utilize that particular technology.

Sources are free to utilize other advanced technologies – such as chemical looping or oxy‐

combustion – to meet the proposed standard of performance.]

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

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

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

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

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

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

that could enable them to meet the standard, but noted that it would be “more difficult” for

them and would entail somewhat higher cost; thus, EPA considered separate standards for the

older kilns but ultimately decided against that approach.

[EPA Response:  The EPA appreciates this recommendation and we will consider the merits of

citing this ruling.]

 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.   

[EPA Response:  It was not EPA’s intent to imply that net compliance costs must be negative.  In

both Section VII.F of the preamble which discusses cost and the RIA which shows that there are

cases where EOR revenue does not fully offset the cost, EPA believes it has made this clear.   We

agree with the commenter that it is important to be clear that costs are still reasonable even if

costs are not fully offset.  We would be happy to discuss further where commenters believe this

was not made clear and how we could do so.]

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

doesn’t appear to consider additional 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?
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[EPA Response:  EPA considered this comment but ultimately decided not to include the

evaluation in the economic analysis.  The amount of oil produced through EOR with captured

CO2 from new EGUs subject to this proposal, while useful from the standpoint of promoting

energy independence, would not be likely to impact cost and thus would not be likely to impact

on total oil consumed. As a result, EOR is not likely to impact total CO2 emissions from oil

production and consumption. ]

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

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

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

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

on this issue in the preamble.

[EPA Response: We will consider adding a reference to a rulemaking under a related area of the

Clean Air Act in which revenues from the sale of pollution control byproducts was treated as

defraying the costs of the pollution control equipment.]

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.

[EPA Response:  The EPA is currently considering this comment and re‐evaluating the range of

emission limitation on which comments will be solicited in the proposal.]

 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,

yielding up to 90% capture and more or less pure H2), but think the overall justification still

needs further elaboration.
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[EPA Response:  The EPA is currently adding additional explanation and justification for the

proposed level of the standard for boilers and IGCC units.  Please note, however, that BSER is

not set at “45% capture”; rather, the emission limit is proposed at 1,100 lb CO2/MWh which

corresponds roughly at a capture level of 45% for a new PC unit.  This will be further explained in

the revised language in the preamble.]

 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.

[EPA Response: As explained in the preamble, the EPA has previously offered sources optional,

longer‐term emission standards that are discounted from the primary emissions standard in

exchange for the longer averaging period. We also specifically request comment on the

appropriate numerical standard such that the 60‐operating‐month standard would be as

stringent as or more stringent than the 12‐operating‐month standard.  We will also reevaluate

the preamble text to determine if further clarification of this point would be useful. ]

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

factor into compliance determinations?

[EPA Response:  

The following is an example of how a CHP facility would calculate an emissions rate for

determining compliance with the 1,000 lb CO2/MWh or 1,100 lb CO2/MWh standard, as

applicable.  

Example plant specifications:

100 MW electric output

500 MMBtu/h of useful steam output

200,000 lb CO2/h measured emissions rate

The 500 MMBtu/h thermal output rate would be converted to an equivalent MW of output

(3.412 MMBtu/h = 1 MWh).  500 MMBtu/h = 147 MW.  The resultant value would be multiplied

by 75% to get a value of 110 MW that would be used in calculating the facility emissions rate.

The emissions rate for comparison against the applicable emissions standard would be (200,000

lb CO2/h) / (100 MW + 110 MW) or 950 lb CO2/MWh.   ]

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

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

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

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

basis for a coal‐CCS plant, which differs little from the (gross) coal without CCS performance
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numbers noted for high performing units of 1434 lb CO2/MWh (p. 188; p. 200), at least at first

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

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

numbers rather than stated in the text.   

Gross Emissions  

(lb CO2/MWh)

Parasitic Load Net Emissions  

(lb CO2/MWh)

SCPC 1675 ‐ 1783 <7.5% [1800 ‐ 1916]

IGCC 1434 15% [1649]

Coal‐CCS 1100 [27%] 1400

NGCC (<=850 MMBtu) 1100 2.5% 1130

NGCC (>850 MMBtu) 1000 2.5% 1030

[EPA Response:  We have specifically solicited comment on the use of net‐based standards and

we will reevaluate that preamble text and clarify as needed. We will also add additional

discussion of the differences in net and gross output‐based standards. ]

Simple Cycle/Peaking plants:   

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

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

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

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

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

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

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

energy growth?

[EPA Response:  We are still considering this comment.]

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

to the same standards as combined cycle units. However, rather than entirely exempting simple

cycle units, EPA could formulate an alternative standard in recognition of the role simple cycle

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

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

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

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

expands.  

[EPA Response:  We are still considering this comment.]

 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
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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?  

[EPA Response:  See response to next comment.]

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

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

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

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

graph and memo would be helpful.

[EPA Response: The vast majority of simple cycle turbines have capacity factors that are

consistently less than 10% on both an annual and 3 year average basis. More than 80% of simple

cycle turbines consistently operated at annual capacity factors below 10% between 2000 and

2012 and over 90% operated at less then 10% capacity on a 3 year average. The figure below

shows the maximum capacity factors of simple cycle turbines and that extending the averaging

period to 3 years results in lower average maximum capacity factors.  Further, please remember

that this proposed rule will only affect NEW units – those that commence construction after the

date of publication of the proposed rule in the Federal Register.  There will be no effect on

existing source EGUs or simple cycle combustion turbines.]

0%

2%

4%

6%

8%

10%

12%

10% ‐ 15% 15% ‐ 20% 20% ‐ 25% 25% ‐ 30% 30% ‐ 33% 33% ‐ 40% 40% ‐ 50% 50% ‐ 60% > 60%

Percent of Simple Cycle Turbines

Capacity Factor

Simple Cycle Turbine Maximum Capacity Factor

Single Year Capacity Factor

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

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

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

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

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

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

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

[EPA Response: The current definition of potential electric output only considers the heat input

capacity of the facility and does not account for efficiency. A 33% efficient 100 MW facility

would have a heat input of 1,034 MMBtu/h and a 40% efficient 100 MW facility would have a

heat input of 853 MMBtu/h. The current definition of potential electric output assumes the

facility is 33% efficient and runs continuously for the entire year at maximum capacity.   

(1,034 MMBtu/h)*(1 MWh/3.412MMBtu/h) *(0.33) * (8,760h/yr) = 876,000 MWh/yr

(853 MMBtu/h)*(1 MWh/3.412MMBtu/h) *(0.33) * (8,760h/yr) = 723,000 MWh/yr

The proposed definition would permit the 40% efficient facility to use the actual efficiency of the

facility

(853 MMBtu/h)*(1 MWh/3.412MMBtu/h) *(0.40) * (8,760h/yr) = 876,000 MWh/yr   ]

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

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

[EPA Response: Smaller NGCC are inherently less efficient than larger NGCC facilities, regardless

of geographic conditions. Applicability under subpart KKKK is currently based on the heat input

capacity of the individual combustion turbine engine and we are not proposing to amend that

approach. As currently written, a combined cycle facility with 2 turbine engines with individual

heat input ratings of less than 850 MMBtu/h using a common steam turbine would be subject to

the less stringent standard even though the combined input capacity of the turbine engines is

greater than 850 MMBtu/h.]

Technical feasibility of CCS for coal‐fired units:

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

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

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

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

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

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

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

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

commenter therefore believes the rule should incorporate sufficient flexibility to enable
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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.

[EPA Response:  We believe that the proposal as it is currently written already contains

considerable flexibility.  These flexibilities include a requirement for an emission limitation that

requires only partial capture and a 12 operating month rolling average – or an alternative 60

operating month rolling average – ARE FEATURES THAT provide considerable flexibility.  The

commenter suggests that “the rule should incorporate sufficient flexibility to enable additional

demonstration projects” but does not suggest specific flexibilities. The EPA is happy to discuss

whether any additional flexibility to promote additional implementation and demonstration of

CCS technology are necessary.]

 EPA’s assertion of the technical feasibility of carbon capture relies heavily on literature reviews,

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

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

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

the rate of 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 Response:  The EPA believes that the evidence supports the finding that

implementation of CCS technology to meet the proposed standard is technically feasible.  

However, the EPA will reevaluate the preamble text and look for opportunities to further

clarify the basis for that finding. The draft preamble explains the standards adopted by the

D.C. Circuit for determining whether a system of emission reduction is “adequately

demonstrated.” (pages 159‐160)  The preamble then identifies the literature and actual

experience with the various components of CCS. (pages 204‐210). These meet the standards

identified by the D.C. Circuit.]

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

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

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

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

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

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

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

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

[EPA Response:  We believe that this proposed rule which will require new fossil fuel‐fired

boilers and IGCC units to capture a fraction of the produced CO2, can incentivize further

development of carbon capture technologies.  In contrast, an emission limitation based on “best

generating technology” would offer no clear incentive for additional CCS research, development
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and demonstration (since such a standard would be met with no need for CCS technology) and

could in fact inhibit that technology (because many PUCs may not find it a prudent cost if it is

not explicitly required).  The EPA will review the current language on page 199 (as directed by

the commenter) and clarify as needed.]

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

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

place in EPA’s introductory power point.

[EPA Response:  A discussion of the Boundary Dam project will be added.  The EPA appreciates

this comment as the exclusion was an oversight.]

Costs of CCS:

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

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

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

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

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

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

capture components.  A technical explanation would be helpful

[EPA Response: The EPA appreciates this comment and will edit the preamble text to provide

additional technical detail on the differences in cost of implementation of partial vs full capture.]

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

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

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

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

footnote?

[EPA Response:  EPA plans to adjust the natural gas price assumed for the baseline NGCC

estimate to $6.11/MMBtu (what EPA has identified as the 2020, 20‐year levelized fuel price),

producing a LCOE of $59.4/MWh.  The remaining differential is attributable to differences in

cost/performance, financial assumptions, and the assumed cost of natural gas.]

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

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

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

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

recognizing the level of uncertainty in these estimates.   

[EPA Response:  We did not receive the referenced attachment of DOE/NETL CCS costs but will

consider additional preamble discussion about the uncertainties in cost.]
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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 Response:  The EPA is aware of the DOE’s program to sponsor research on novel carbon

capture technologies. We will edit the proposal to indicate the program and acknowledge its

potential to further develop better performing and more economical capture technologies.]

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

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

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

them.  (See page 230).

[EPA Response:  As suggested, the EPA will edit the preamble to list the specific proposed

regulatory programs that have contained such provisions for CCS.]

 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 Response:  EPA is adding a more detailed discussion to the preamble regarding

transportation of CO2.]

 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).

[EPA Response:  EPA is adding a more detailed discussion to the preamble regarding

transportation of CO2.]

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

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

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

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

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

[EPA Response:  The EPA will supplement the preamble with language detailing why the

assertion that CO2 transportation costs do not represent “a significant impediment” to CCS is

robust to the cost and uncertainty factors highlighted by the commenter.  Similarly, EPA will add

language to the preamble (similar to the language contained in the RIA) that acknowledges the

regional variability of transportation costs.  In regards to the last sub‐bullet, EPA believes new or

existing gas‐fired generation can serve as a substitute for a coal‐fired power plant (the comment

seems to imply that increasing dispatch of existing natural gas‐fired facilities is the only

substitute contemplated).  The identical projections of the baseline and regulated scenarios over

the analysis period signify that – based on our current analysis ‐ a significant divergence in

resource and technology development paths are unlikely.]

Geologic Sequestration:

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

Class VI.  

[EPA Response: This rule does not change the classification of an Underground Injection Control

(UIC) well in the UIC Program.  As noted in the proposed NSPS preamble, a covered entity

employing CCS to meet the performance standard is required to supply its CO2 to a facility

reporting under subpart RR of the GHG Reporting Program.  The facility reporting under subpart

RR can hold a UIC Class II or UIC Class VI permit. That permitting determination is made under

the UIC regulations.   For a discussion on UIC Class II wells transitioning to Class VI, please

consult the preamble to the final UIC Class VI rule, December 10, 2010, 75 FR 77230 et seq. ]

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

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

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

Reporting Rule Subpart RR.  The FR text on page 255, refers to the use of both UIC Class II and

Class VI wells under GHG Reporting Rule SubPart RR as verification of sequestration for the

purposes of the NSPS.   

[EPA Response:  The EPA appreciates comments on the rulemaking related to the hazardous

waste conditional exclusion for UIC Class VI wells.  The EPA is considering those comments as

part of that separate rulemaking process.]

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

the factual basis for determining that the long‐term storage of 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
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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 Response:  As requested, EPA has added additional language to the preamble regarding

sequestration of CO2]

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

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

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

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

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

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

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

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

case, where local pollution does not have local effects.

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

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

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

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

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

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

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

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

the country.

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

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

NAAQS or PSD.

[EPA Response:  The preamble accurately describes the legislative history and its relevance.  The

preamble also explains why CCS with partial capture is attainable throughout the entire country,

and is not inappropriate for particular parts of the country.]

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

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

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

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

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

leakage occurs.  EPA should discuss this aspect of the overall approach.
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[EPA Response: The EPA used its authority under section 114 of the Clean Air Act to promulgate

the Greenhouse Gas Reporting Program (GHGRP) requirements.  A failure to comply with the

monitoring and reporting requirements of the GHGRP is a violation of the Clean Air Act.  The

proposed amendments to 40 CFR Part 98 subpart PP will provide the information necessary for

EPA to determine whether the captured CO2 is reported under the GHGRP.   

As the commenter noted, affected units using CCS to comply with the performance standard

would be required to send their captured CO2 to a facility that reports under subpart RR of the

GHGRP. ]

 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.  

[EPA Response: The issue is outside the scope of this rulemaking as the only requirement for the

affected EGU is to send it to a source covered by Subpart RRR.]

CCS for Natural Gas:

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

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

NGCC.  EPA does helpfully note that 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?  

[EPA Responses:  To clarify, in the current draft of the preamble we state that ... “we believe

there is insufficient information to make a determination regarding the technical feasibility”.  

We did not intend to state definitely that implementation of CCS on a NGCC unit is “not

technically feasible” and we will review the text to ensure that we have not inadvertently done

so.  We will also consider additional technical constraints or challenges to using CCS w/ NGCC

and will also discuss other factors in greater detail.]

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

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

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

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

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

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

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

[EPA Responses:  In the current version of the DRAFT preamble, the EPA did not find CCS to be

BSER for NGCC units because we believe that there is insufficient information to determine its
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current feasibility.  Therefore we did not conduct a cost analysis as we had already eliminated it

as a BSER option.]

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

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

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

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

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

 [EPA Response:  Please note that we do not consider CCS with NGCC units to be “infeasible”.  

Rather, we believe that there is insufficient information to determine its feasibility at this time.

We will consider soliciting comment on this determination.]

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

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

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

EPA may consider requesting comment on further subcategorization.

[EPA Response:  We appreciate this comment and we are considering the merits of requesting

comment on further subcategorization for natural gas‐fired stationary combustion turbines.]

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

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

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

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

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

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

although there might be better ways to send this signal.   

[EPA Response: The EPA appreciates this comment and will consider what preamble edits may

be appropriate.]

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

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

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

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

not been “adequately demonstrated,” that we do not have sufficient economic information to

determine if NG‐CCS costs are reasonable, and there are differences in system design and 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
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news reports from GE‐Sargas and Summit‐Linde that they are independently proceeding with

NG‐CCS design and funding proposals.   

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

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

competition

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

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

Alliance‐Enhanced‐Oil‐Recovery

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

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

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

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

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

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

best system of emission reductions adequately demonstrated for new stationary

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

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

insufficient information to make a determination regarding the technical feasibility of

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

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

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

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

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

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

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

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

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

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

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

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

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

lead to uncertainty about how technically feasible CCS technology might be

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

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

capture) at varying turbine rates.]

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

technologies have not been adequately demonstrated and there are uncertainties

regarding the economic about technical feasibility and because of adverse impacts on

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

stationary combustion turbines.”

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

Reject CCS because it has not been adequately demonstrated.   

[EPA Response: The EPA appreciates these specific recommended line‐edits and will consider

them accordingly.]  

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.  

[EPA Response: All new fossil fuel‐fired boiler/steam turbine EGUs (subpart Da) facilities would

be subject to the proposed standards. No new natural gas or oil‐fired subpart Da facilities have

been constructed recently and we do not anticipate any new natural gas or oil‐fired subpart Da

facilities since it is less expensive and more efficient for construct natural gas and oil‐fired

combined cycle facilities. However, GHG standards for combustion turbines (subpart KKKK) are

only being proposed for facilities that burn over 90% natural gas on a heat input basis. New oil‐

fired EGUs constructed in Hawaii and other non‐continental areas are projected to be combined

cycle facilities and not subject to a GHG standard.]
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 Page 81, EPA states: “Note that we are not proposing standards for new steam generating units

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

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

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

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

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

KKKK regulatory text sections?

[EPA Response: An oil‐fired combustion turbine in Hawaii would be an example of a combustion

turbine not subject to an emissions standard. Table 2 in subpart KKKK will be clarified to specify

that the standards only apply to facilities that combust over 90% natural gas on a heat input

basis on a 3 year average period. Subpart Da would cover a new oil‐fired boiler/steam turbine

based EGU. ]

 Page 119, EPA states: “Rather, the EPA is simply promulgating new standards of performance for

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?

[EPA Response: See response to the previous comment.]

Combined heat and power:  

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

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

benefits.

[EPA Response: We have concluded that the transmission and distribution benefit and thermal

output credits sufficiently recognize the environmental benefit of CHP. We will be happy to

discuss whether anything further would be appropriate.

Biomass:  

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

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

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

by the facility?

[EPA Response:  EPA recognizes the potential emissions benefits of co‐firing with biomass. In

September 2011, EPA submitted its Draft Accounting Framework for Biogenic CO2 Emissions

from Stationary Sources to the Science Advisory Board (SAB) Biogenic Carbon Emissions (BCE)

Panel for peer review.  The SAB BCE Panel delivered its Peer Review Advisory to OAR on
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September 28, 20121

, and EPA is evaluating the peer review comments in order to determine

the most appropriate method of accounting for CO2 emissions from biogenic feedstocks in the

regulatory context.  The overall net atmospheric impact of using a biogenic feedstock will

ultimately depend on the stationary source process and the type of feedstock used, as well as

the conditions under which that feedstock is grown and harvested.]   

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

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

benefits.

[EPA Response: See above response.]

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

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

permitting, should that be mentioned in the preamble?

[EPA Response:  See above response.]   

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

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

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

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

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

[EPA Response:   EPA recognizes the potential emissions benefits of co‐firing with biomass.  In

July 2011, EPA deferred for a period of three years the application of the Prevention of

Significant Deterioration (PSD) and Title V Programs (76 FR 43490) to biogenic CO2 emissions

from stationary sources in order to conduct a detailed examination of the scientific and

technical issues associated with those emissions.  On July 12, 2013, the United States Court of

Appeals for the District of Columbia Circuit issued its decision in Center of Biological Diversity v.

EPA, No. 11‐1101 (D.C. Circuit), vacating EPA’s July 2011 deferral rule.  The Agency will evaluate

the Court’s decision and the scientific and technical considerations described above as it

determines the next steps. ]  

PSD and Title V Program:

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

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

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

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

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

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

                                                           

1 The text of the Peer Review Advisory can be found here:  

http://yosemite.epa.gov/sab/sabproduct.nsf/0/2f9b572c712ac52e8525783100704886!OpenDocument&TableRow

=2.3#2.
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permitting discretion” as a defense, so it would be useful to clarify this sentence about state

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

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

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

permitting process).

[EPA Response:  The EPA will consider this recommendation and edit accordingly.]

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

“Under the PSD program in part C of title I of the CAA, in areas that are classified as attainment

or unclassifiable for NAAQS pollutants, a new or modified source that emits any air pollutant

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

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

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

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

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

[EPA Response:  The EPA will consider this recommendation and edit accordingly.]

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

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

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

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

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

charge adequate fees?  

[EPA Response: We are seeking comment in the proposal on the level of fee revenue increase

necessary to fully fund the cost of permitting GHGs as part of any state operating permit

program that has based its fee adequacy demonstration on the presumptive minimum fee that

is defined in our regulations; it is not an option for such states to collect fees that would, in the

aggregate, be less than necessary to fund their operating permit program. Nevertheless, we will

review the preamble text describing the two options for charging fees for GHGs and potentially

revise existing language or add new language to compare the two options with respect to their

ability to result in the collection of adequate fees to fund GHG permitting.]  

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 Response: The EPA will consider adding clarification and/or further discussion of the

legality of emissions trading in the CAA §111(b) context for new sources.]
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 EPA may wish to discuss whether emissions trading options would be economically efficient and

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

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

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

benefit.   

[EPA Response: see above]

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

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

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

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

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

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

new sources?   

 [EPA Response: see above]

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

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

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

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

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

[EPA Response: There is no need in this preamble, which concerns new sources, to address

trading for existing sources.  What is the BSER for new sources may differ from the BSER for

existing sources due to, for example, different cost considerations.]

Existing sources:

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

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

from existing sources?  

[EPA Response:  Under CAA §111(d), the EPA may not promulgate requirements for existing

sources before it has promulgated standards of performance for new sources.]

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

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

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

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

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

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

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

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

, is a particularly expensive proposition.”

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

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

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

CCS.

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

full CCS requirement for future existing sources.

[EPA Response: These questions appear to concern the following paragraph in the preamble:

In addition, identifying CCS as the BSER for coal can be seen as beneficial to coal‐

fired electric generation, and therefore fuel diversity, over the long term. This is

because identifying CCS as BSER eliminates uncertainty as to future control

obligations for coal‐fired capacity. Any new coal‐fired source that constructs

without CCS faces the risk that future state or federal controls may require

carbon capture, which would require the source to retrofit CCS, which, in turn, is

a particularly expensive proposition. This risk is heightened because power

plants are generally long‐lived – in some cases, XX years – and the risk of future

carbon limitations can be expected to remain throughout that period.

(p. 240).  We believe this paragraph is clear on its face, but we are prepared to discuss any

aspects of it with the commenter.]

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

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

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

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

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

[EPA Response:  No existing sources will need to comply with the proposed standard.  However,

as we have noted, the vast majority of recently constructed existing source NGCC units already

meet the proposed emission standard for stationary combustion turbines.]

Regulatory Impact Analysis:  

General comments

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

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

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

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

of RIA.  

[EPA Response: As requested, the EPA will revise the RIA accordingly.]
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 Clarify baseline years and period of analysis. The RIA refers to a base year of 2020, achieving

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

[EPA Response: 2020 data and modeling are used as a proxy for the 2022 year of analysis. We

will revise RIA to make references to this consistent.]

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

clarify the role of CSAPR given its current status.

[EPA Response: The legal status of CSAPR and CAIR makes no difference in this rule’s evaluation

because they make no difference in the type of new capacity additions projected to be

economic.]

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

[EPA Response:  The EPA has not consulted with NRC and FERC over the specific nuclear

projections contained in either the IPM or NEMS modeling; however, NRC orders, amendments,

and guidance are reflected in modeling assumptions and tested in scenario development,

thereby directly impacting nuclear uprate, retirement, and capacity expansion projections.]

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

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

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

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

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

select, in choosing among alternative regulatory approaches, those approaches that maximize

net benefits (including potential economic, environmental, public health and safety, and other

advantages; distributive impacts; and equity);”

[EPA Response: The EPA will revise the footnote to read:  EO 13563 states that each agency

must “propose or adopt a regulation only upon a reasoned determination that its benefits justify

its costs (recognizing that some benefits are hard to quantify).” While the presence of net

benefits for a given regulatory option is not the only condition necessary for optimal regulatory

design, it does signify that the regulatory option is welfare improving for society.]

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

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

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

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

[EPA Response:  The EPA will reevaluate the language and clarify as appropriate.]

 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)?

[EPA Response:  The EPA has detailed examples of existing sources that have demonstrated CCS

and of facilities that are very near completion of construction that will utilize CCS.  The EPA used

data from the DOE/NETL cost and performance reports for estimates of LCOE.]

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

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

[EPA Response: Yes, some of the 16 projects that are under construction or at an advanced

stage of planning that intend to use captured CO2 for EOR are coal power plants, including

Southern Company’s Kemper County Energy facility, Summit Power's Texas Clean Energy Project

and the Hydrogen Energy California Project.]

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

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

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

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

following ways:  

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

from legislation designed to stimulate the economy during a recessionary period

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

to expire as the economy improves.

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

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

 Complex application processes: Department of Energy financial assistance and

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

application process

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

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

and therefore must prioritize its assistance

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

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

industry, without application and not subject to appropriations.
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[EPA Response: The EPA recognizes that federal and state assistance are not guaranteed; the

EPA simply attempted to point out that subsidies have been available in the past and may be

available for future projects to help defer some costs.  We will check the existing language in the

preamble and RIA to ensure that we have not indicated that we have expected those subsidies.]

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

specific examples of uncompleted CCS projects.

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

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

idealized estimates

 The Southern Kemper County Project is experiencing substantial cost

overruns of hundreds of millions dollars

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

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

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

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

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

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

governments

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

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

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

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

additional tax benefits for EOR.  

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

overwhelming cost and risk factors that have forced previous government‐

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

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

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

program. According to the Congressional Research Service, these

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

overruns or uncertainty regarding the effectiveness and efficiency of the

CCS technology.

[EPA Response: The EPA will reevaluate the text in the preamble and the RIA to ensure that we

have not misrepresented any costs associated with any of the existing plants that are currently

(or imminently) being constructed.]

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?
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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?  

[EPA Response:  Yes, there is a significant increase in assumed LNG export capacity – new

liquefaction capacity is projected to start at 0.6 billion cubic feet per day in 2016, increasing to

4.5 billion cubic feet per day in 2027.  In the AEO2013 Reference Case, U.S. exports of

domestically sourced LNG are projected to reach 1.6 trillion cubic feet per year in 2027.  LNG

export levels significantly exceed this amount in the ‘High Oil and Gas Resource’ scenario.  The

natural gas price projections of the Reference Case and High Oil and Gas Resource scenario are

both included in the RIA.]

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

economic conditions

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

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

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

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

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

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

likely undervalue the future demand for electricity.

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

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

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

gas prices.

[EPA Response:  Short‐term movements in the PPI are volatile and generally not relevant to

defining the appropriate inputs to a long‐term, fundamentals‐based model such as IPM and

NEMS.  The demand derivation EPA utilizes from EIA does not rely on data biased by poor

economic conditions; it is the result of considered forward views by industry experts of

economic growth, energy intensity, and primary energy use by sector, among many other key

drivers.  Specifically, GDP growth is more a function of expected future labor force participation,

capital stock growth, and worker productivity than the simple continuation of a slow economic

recovery.  The 2.5% average GDP growth (2011‐2040 average) that underlies the Reference Case

is broadly consistent with official estimates and is supplemented in EPA’s analysis by both a High

Economic Growth scenario as well as a Low Economic Growth scenario.  EPA is open to

discussing the issue.  For a concise overview of the demand derivation underlying the AEO2013

runs, please refer to the ‘Market Trends’ section (page 55) of the full AEO2013 report.
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On the issue of natural gas price volatility, the RIA contains the following paragraph:

“Short‐term fuel price volatility is not relevant in this context because new power plants have

asset lives measured in decades, not in months or years, and new capacity investment decisions

are based on long‐run expected prices, not month‐to‐month, or even year‐to year, variations in

fuel prices.  Shorter‐term prices will affect how units are dispatched, but these potential

dispatch impacts are considered over a longer time horizon and factored into the choice of

which type of plant to build.  In contrast, the uncertainty surrounding long‐term fuel prices will

exert significantly greater influence on the technology selected for new capacity additions. In a

modeling context with perfect foresight, this longer term uncertainty may be evaluated by the

scenario testing presented throughout this analysis.”  We are open to discussing this issue,

including the role of natural gas price hedging and how the trend from offshore to onshore

production has impacted the relationship between past and expected future natural gas price

volatility.]

NETL study.

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

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

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

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

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

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

subtraction of the transmission cost estimates.  

[EPA Response:   The NETL cost numbers excluded the following from the capital costs:

1. Escalation to period‐of‐performance

2. Owner’s costs – including, but not limited to land acquisition and right‐of‐way, permits

and licensing, royalty allowances, economic development, project development costs,

allowance for funds‐used‐during construction, legal fees, Owner’s engineering,

preproduction costs, furnishings, Owner’s contingency, etc.

3. All taxes, with the exception of payroll taxes

4. Site specific considerations – including but not limited to seismic zone, accessibility, local

regulatory requirements, excessive rock, piles, laydown space, etc.

5. Labor incentives in excess of a 5‐day/10‐hour work week

6. Additional premiums associated with an EPC contracting approach   ]

 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?
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 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.  

- 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?
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- 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?

[EPA Response: The EPA will reevaluate the existing text in the draft preamble and RIA and

clarify according to the above recommendations as appropriate.]

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.   

[EPA Response:  This proposed rule does have some additional data elements required to be

reported to EPA electronically and these few data elements impose negligible burden.  This data

is minimal and needed to ensure compliance with the emissions limits set in the proposed rule. ]

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

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

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

rather than have a potential use.

[EPA Response:  The reporting under this rule is to ensure compliance with the CO2

emissions limits set under the proposed rule.  The information is needed to determine

compliance with a Part 60 regulation and is different than what the Part 98 GHG

reporting rule requires.]

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

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

nothing to enforce.
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[EPA Response:  The EPA is proposing standards of performance and must also specify

reporting and recordkeeping requirements for those standards.]

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.  

[EPA Response: The CO2 emissions limits are based on using the categorizations of Part

60 Subparts Da and KKKK.  If new electric generating technology is developed a new

NSPS would need to be developed to cover the technology.  When that is

proposed/promulgated a new CO2 limit would need to be set along with other

applicable criteria pollutant limits.]

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

requirements should be sufficient to ensure compliance with the NSPS. Alternatively, all

units subject to the NSPS should be exempted from the separate GHG reporting

requirements.

[EPA Response: The proposed NSPS requirements rely on the existing electronic

reporting framework currently employed by Part 75.  The proposed amendments to the

GHG Reporting Program are not redundant with the proposed NSPS requirements;

rather, the GHG Reporting Program framework is used to ensure that CO2 captured at

an affected unit is transferred to a facility reporting geologic sequestration.]

Editorial/technical comments:

Preamble

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

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

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

[EPA Response: Agreed

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

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

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

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

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

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

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

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

[EPA Response: Agreed]

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

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

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

with this 40 percent sales criterion on a single‐year basis, as a practical matter, it is anticipated

that few new simple cycle turbines would be subject to the proposed standards of

performance.”

[EPA Response: Agreed]

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

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

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

is not “twice as large or more.”

 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.”  

[EPA Response: As requested, the EPA will revise the text accordingly.]
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 Page 5‐1, second paragraph, last sentence before the bullet points: Should 2022 be 2020? We

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

[EPA Response: 2020 data and modeling are used as a proxy for the 2022 year of analysis. We

will revise RIA to make references to this consistent.]

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

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

assumptions.  

[EPA Response: As requested, the EPA will revise the text accordingly.]

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

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

[EPA Response: For this proposed rule, the subcategories are: (1) natural gas‐fired stationary

combustion turbines with a heat input rating to the turbine engine that is greater than 850

MMBtu/hr; (2) natural gas‐fired stationary combustion turbines with a heat input rating to the

turbine engine that is less than or equal to 850 MMBtu/hr; and (3) all fossil fuel‐fired boilers and

IGCC units (regardless of fuel ... i.e., solid, liquid and gaseous fossil fuels.  The preamble and RIA

will be reviewed thoroughly to ensure that we have consistently identified the subcategories. ]

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

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

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

same tables.  

[EPA Response:  There is no 2025 run year in EPA’s IPM projections; the 2020 run year is

mapped to calendar years 2017‐2024 and the 2030 run year is mapped to calendar years 2025‐

2034.  We will consider including 2030 projections.]

 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.

[EPA Response:  The EPA appreciates this comment and is evaluating this further.]

 Also, drop “of these technologies” in paragraph 5.7.  

[EPA Response:  As requested, we will edit to drop “of these technologies”.]

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

originally in the April 2013 TSI using 2007$.

[EPA Response:  As requested, we will add a note about the dollar year of the SCC.]
Summary of Interagency Working Comments on Draft Language under

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 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.  

[EPA Response: As requested, we have double checked these calculations and they are correct.

We added a table of PM2.5‐related benefit per‐ton values to highlight the magnitude of these

values, showing that they can add up quickly.  The valuations attached to the PM2.5 benefits in

table 5‐X on page 5‐42 are derived by taking the difference in SO2 and NOX emissions per‐MWh

from table 5‐19 on page 5‐34, converting to tons (i.e. dividing by 2000 lbs/ton), and multiplying

by the pollutant‐specific benefit per ton discussed on page 5‐40.]

 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.   

[EPA Response: The emissions increase is 23 to 30 tons per year, not lbs/MWh. On a per

megawatt‐hour basis, the emissions increase from 0.003 lbs/MWh to 0.013 lbs/MWh. This

results in a negligible PM2.5 disbenefit per megawatt‐hour, as noted in the footnote to the table

on p. 5‐45. These negligible disbenefits are also included in the calculation of the total benefits

reported in the table.]

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

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

important input number.  Please update.

[EPA Response: As requested, we will update with a reference.]

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

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

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

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

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

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

[EPA Response: As requested, we will revise to clarify.]

Citations

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

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

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

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

[EPA Response: As requested, we will revise to clarify.]
Summary of Interagency Working Comments on Draft Language under

EO12866 Interagency Review.  Subject to Further Policy Review. 

­ EPA RESPONSE ­ 

34

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

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

No. 12‐1248, 2012 U.S. App. LEXIS 25535 (D.C. Cir. Dec. 13, 2012).

[EPA Response: As requested, we will revise to clarify.]