From: Frey, Nathan J.

To: Wayland, Robertj ; Culligan, Kevin ; Hutson, Nick

Subject: RE: Response to summary of comments

Date: Monday, September 16, 2013 5:54:09 PM



### Can you give me a quick call to discuss?

From: Wayland, Robertj [mailto:Wayland.Robertj@epa.gov]

Sent: Monday, September 16, 2013 5:53 PM

To: Frey, Nathan J.; Culligan, Kevin; Hutson, Nick

Subject: RE: Response to summary of comments



### Nathan -

We addressed these concerns in the version of the preamble that Kevin sent over to you on

Friday, September 13th. This is the FOAK vs. NOAK language that we inserted to

accommodate DOE's concerns with the table numbers. Subsequently, we have also shared

the language with DOE/NETL (the contacts you provided earlier), but we haven't gotten any

edits/comments back from them as of right now.

Hope this helps - just let me/Kevin/Nick know if you have further questions.

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, North Carolina 27709

Office: (919) 541-1045

Cell: (919) 306-2290

Fax: (919) 541-5450

Email: wayland.robertj@epa.gov

*****************************************

DRAFT/Deliberative Document - FOIA EXEMPT

*****************************************



### From: Frey, Nathan J. < Nathan_J._Frey@omb.eop.gov >

Sent: Monday, September 16, 2013 5:32 PM

To: Culligan, Kevin; Wayland, Robertj; Hutson, Nick

Subject: FW: Response to summary of comments

Hi all,

### I just wanted to follow up to see if a response to the attached is still pending? Thanks

Nathan

From: Frey, Nathan J.

Sent: Friday, September 13, 2013 5:30 PM

To: Culligan, Kevin; Wayland, Robertj; Hutson, Nick

Subject: RE: Response to summary of comments



### Please find attached a summary of follow up interagency comments in response to the latest EPA

responses. Please let me know if you would like to discuss.

From: Culligan, Kevin [ mailto:Culligan.Kevin@epa.gov ]

Sent: Thursday, September 12, 2013 8:32 PM

To: Frey, Nathan J.; Wayland, Robertj; Hutson, Nick

Subject: Response to summary of comments



### Attached find responses to the interagency comments. We’ll get you the preamble tomorrow. I

will call to discuss the rest of the schedule and your other big picture question. Is there a good

time to call (if you get back to me tonight, I can be available any time tomorrow – if I don’t hear

from you tonight, I’ll be out of pocket on the metro somewhere between 8:00 and 9:00 but will be

able to touch base any time after 9:00 AM). Also, could you remind me your direct #? I’ll be in an

off-site meeting at least part of the day, but can be reached at 240-426-1025.

- Kevin

From: Frey, Nathan J. [ mailto:Nathan_J._Frey@omb.eop.gov ]

Sent: Monday, September 09, 2013 9:58 PM

To: Wayland, Robertj; Culligan, Kevin; Hutson, Nick

Subject: Summary of Interagency Comments Under EO 12866/13564 EGU GHG NSPS



### Hello all,

Please see attached summary of interagency comments with respect to the latest round of edits

provided by EPA. We look forward to discussing these remaining comments with EPA on

tomorrow’s 10:30am interagency conference call.

Thanks and please let me know if you have any questions.

Nathan

## Summary of Interagency Working Com ments on Draft Language under

EO12866 Interagency Review.  Sub ject to Further Policy Review.

Some commenters remain concerne d that retaining the original values in Table 4 does not

accurately portray the current cost of CCS. The single value, "next-of-a-kind" costs

currently in Table 4 represent the expect ed costs after sign ificant learning and

demonstrations have taken place. This learni ng hasn't occurred yet. Therefore, since

Table 4 does not include the range of costs pr eviously provided, we believe current cost

of CCS is not accurately represented.

Further, the studies from which many of th e costs in Table 4 ar e derived are explicit

regarding their level of uncer tainty. Since Table 4 doe s not clearly present this

uncertainty (-0%/+30%), commenters remain c oncerned that the results of the study are

being misrepresented.

Table 1 – Cost of Electricity Estimates fo r Power Generation with and without CCS

Technology Cost of Electricity

($2011/MWh)

CO 2 

### Capture,

% CO 2 

### Emission

Rate,

lb/MWh-gross Capacity

Factor,

% EPA NETL

recommendati

on (next-of-akind) i 

### NETL

recommend

ation (firstof-a-kind)

NGCC ii 

### 0 790 85 60 – 77

50 71 - 92

24 600 85 69 - 90 79 - 103

50 85 - 110 97 - 125

40 480 85 74 - 97 84 - 111

50 92 - 120 105 - 137

90 87 85 90 - 118 103 - 135

50 115 - 149 131 - 170

SCPC 0 1,675 85 92 91 - 118

40 1,100 85 110 110 – 143 121 - 157

90 202 85 147 147 - 191 162 - 210

IGCC 0 1,433 80 97 101 - 131

25 1,100 80 109 112 - 146 129 - 168

## Summary of Interagency Working Com ments on Draft Language under

EO12866 Interagency Review.  Sub ject to Further Policy Review.

90 152 80 136 142 - 185 163 - 213

Kemper

IGCC ~65 541 iii 

### 80 ~170 iv



### Nuclear 103 – 114

i Values reported by NETL are first-year, nominal dollar COEs that include a cost of $10/tonne for

transport and storage of captured CO 2 . NGCC COEs assume a delivered natural gas price of

$6.13/MMBtu. All coal plants assume bituminous coal at a delivered cost of $2.94/MMBtu, except for the

Kemper County IGCC which uses lignite coal.

ii NGCC COEs are based on plants th at feature an advanced F-frame ga s turbine. COEs for NGCCs with

more advanced gas turbines (H- or J-frames) would be around 5-10% less for systems without CCS and 7-

14% less for systems with 90% CCS.

iii Source: Page 5, http://www.catf. us/resources/testimony/files/20120920-

Thompson_CATF_Energy_and_Power.pdf

iv This internal NETL estimate (which did not come from Southern Company) is based on the most recent

publicly reported capital cost of ~$7,300/kW for the Kemper IGCC plant (assumed to be a total as-spent

capital cost, excluding costs for the lignite mine and CO 2 pipeline, and calculated based on the plant’s

syngas-based net capacity of ~524 MW) and the following assumptions based on generic NETL system

studies: an O&M cost of $54/MWh including fuel, a capit al charge factor of 0.124, and a capacity factor of

80%.[Type text]



## Summary of Interagency Working Com ments on Draft Language under

EO12866 Interagency Review.  Subje ct to Further Policy Review.



## ­ EPA Response

­

1 1. EPA’s CCS costs were based on NETL’s “next

‐ of

‐ a

‐ kind” COE estimates, but the technology’s

current first

‐ of

‐ a

‐ kind costs should be used instead

[EPA Response: As suggested, we have added language to indicate that the costs in Table 4 of the

preamble (and in Chapter 5 of the RIA) represent “next

‐ of

‐ a

‐ kind” costs.]

It is recommended that EPA clarify that the COEs of coal generation with CCS in Table 4 (Levelized Cost

of Electricity for Electric Generating Technologies, Excluding Transmission Costs) of “Standards of

Performance for Greenhouse Gas Emissions from New Stationary Sources: Electric Utility Generating

Units” are representative of future, nth

‐ of

‐ a

‐ kind plants and do not reflect the present cost of

commercial offerings, which are substantially higher.

In order to more accurately portray the current cost of CCS, it is suggested that Table 1 below should

replace Table 4 (Levelized Cost of Electricity for Electric Generating Technologies, Excluding

Transmission Costs) of “Standards of Performance for Greenhouse Gas Emissions from New Stationary

Sources: Electric Utility Generating Units.”

For an emerging technology like CCS, costs can be estimated for a first

‐ of

‐ a

‐ kind (FOAK) plant or an nth

‐

of

‐ a

‐ kind (NOAK) plant, the latter of which has lower costs due to the “learning by doing” and risk

reduction benefits that result from serial deployments as well as from continuing R&D. For a power

plant based on fully mature technology, such as a supercritical pulverized coal plant without CO 2

capture, NETL’s estimates are for an NOAK plant. For plants that utilize technologies that are not fully

mature, such as IGCC or any plant with CO 2 capture, NETL’s cost estimates are for a plant that is

somewhere between FOAK and NOAK, sometimes referred to as “next

‐ of

‐ a

‐ kind”. These “next

‐ of

‐ a

‐

kind” estimates do not include the cost premiums associated with FOAK demonstrations and are

probably closer to NOAK costs than FOAK costs.

Accordingly, it should be noted that EPA’s COE estimates for power plants with CO 2 capture, which are

based on NETL’s “next

‐ of

‐ a

‐ kind” values, are more representative of future NOAK commercial offerings

and do not reflect the much higher costs currently being realized by FOAK demonstration plants. For

example, NETL expects the actual CO 2 mitigation costs for two of its FOAK coal CCS demonstration

projects (the WA Parish PC Plant and the Kemper County IGCC plant) to be 35

‐ 80% higher i than the more

mature costs projected by the referenced NETL studies. While much of this cost premium may be

attributable to differences between the actual design, scope and scale of the demonstration projects

compared to what was assumed for the NETL studies, at least some of the cost delta is certainly

associated with FOAK issues.

An NETL study on technology learning curves ii examined how “learning by doing” might reduce the cost

of an IGCC plant with CO 2 capture by applying a different learning rate to each plant subsystem

consistent with its maturity level. Learning rates varied from 0.01 for very mature technologies to 0.06

for FOAK technologies. For the overall IGCC system, it was estimated that the NOAK cost could be 15%

lower than the FOAK cost. Using the same approach, the study estimated that NOAK costs for PC and[Type text]



## Summary of Interagency Working Com ments on Draft Language under

EO12866 Interagency Review.  Subje ct to Further Policy Review.



## ­ EPA Response

­

2 NGCC plants with CO 2 capture could be 10% and 14% lower than their FOAK costs, respectively. These

relationships between FOAK and NOAK costs were used to estimate the FOAK costs in Table 1.

As shown in the table, a rough projection of COE for the Kemper County IGCC falls near the bottom of

the range of NETL’s estimate for a FOAK IGCC plant with 90% CO 2 capture. It should be noted that the

Kemper IGCC will capture somewhat less CO 2 (67% versus 90%) and that the design basis of the Kemper

IGCC differs somewhat from that assumed by the NETL studies (e.g., different gasification technologies,

lignite coal versus bituminous coal). It should also be noted that the Kemper IGCC plant is still under

construction and may experience additional increases in cost.

Table 1

– Cost of Electricity Estimates for Power Generation with and without CCS

Technology Cost of Electricity

($2011/MWh)

CO 2

Capture,

% CO 2 Emission

Rate,

lb/MWh

‐ gross Capacity

Factor,

% EPA NETL

recommendati

on (next

‐ of

‐ a

‐ kind) iii NETL

recommenda

tion (first

‐ of

‐

a

‐ kind)

NGCC iv 0 790 85 60

– 77

50 71

‐ 92

24 600 85 69

‐ 90 79

‐ 103

50 85

‐ 110 97

‐ 125

40 480 85 74

‐ 97 84

‐ 111

50 92

‐ 120 105

‐ 137

90 87 85 90

‐ 118 103

‐ 135

50 115

‐ 149 131

‐ 170

SCPC 0 1,675 85 92 91

‐ 118

40 1,100 85 110 110

– 143 121

‐ 157

90 202 85 147 147

‐ 191 162

‐ 210

IGCC 0 1,433 80 97 101

‐ 131

25 1,100 80 109 112

‐ 146 129

‐ 168

90 152 80 136 142

‐ 185 163

‐ 213

Kemper IGCC ~65 541 v 80 ~170 vi

Nuclear 103

– 114[Type text]



## Summary of Interagency Working Com ments on Draft Language under

EO12866 Interagency Review.  Subje ct to Further Policy Review.



## ­ EPA Response

­

3 2. “Next

‐ of

‐ a

‐ kind” costs will not be realized before more demonstration projects proceed

[EPA Response: We have added language indicating the value of demonstration projects

– including

those that are currently underway or in advanced stages of planning

– in advancing the technology and

lowering implementation costs.]

Despite NETL’s best efforts to accurately estimate costs, it is widely accepted among cost estimation

professionals that projections of NOAK costs for technologies that are still under development are

typically lower than the actual costs that are eventually realized (see Figure 1 below). This “technology

optimism” tends to persist even when substantial process contingencies are applied to early estimates,

and is applicable for CO 2 capture costs as well as CO 2 storage costs, both of which are embedded in the

tabulated COE estimates.

Figure 1

– Technology Cost Curve

In addition to the premiums associated with FOAK plants, another factor that could result in higher costs

than those tabulated relates to the ability of a plant to exceed the proposed 1,100 lb/MWh

‐ gross

regulatory emission limit. The tabulated estimates reflect costs for plants that would precisely meet the

emission limit during steady state operation without any buffer for operational excursions and very

limited flexibility to adjust the CO 2 capture rate in response to market conditions (while still complying

with the regulation on average). Plants designed for additional capture to provide a buffer and/or for

flexible capture rates will cost more.[Type text]



## Summary of Interagency Working Com ments on Draft Language under

EO12866 Interagency Review.  Subje ct to Further Policy Review.



## ­ EPA Response

­

4 3. The NETL costs used by EPA represent the low end of the COE range, but the high end of the

range should also be considered

[EPA Response: We have retained the values originally contained in Table 4 of the preamble and we

explain in the preamble text why we focus on those “next

‐ of

‐ a

‐ kind” costs.]

NETL reviewed the EPA estimates and appended some recommended values to Table 1

. Both EPA and

NETL base their cost estimates on two NETL reports:

1. Cost and Performance of PC and IGCC Plants for a Range of Carbon Dioxide Capture. August

2011. DOE/NETL

‐ 2011/1498.

2. Updated Costs (June 2011 Basis) for Selected Bituminous Baseline Cases. August 2012.

NETL/DOE

‐ 341/082313.

Report 2 estimated costs in June 2011 dollars, while Report 1 estimated costs in June 2007 dollars. For

consistency, the recommended values obtained from Report 1 have been adjusted to be in June 2011

dollars. The recommended values also express an uncertainty range (

‐ 0%/+30%) for each technology

cost instead of a point estimate.

4. The preamble notes on page 29 that biomass

‐ fired generation is a technology that can provide

intermediate or base

‐ load power. It would be helpful if EPA could also address biomass co

‐ firing,

specifically how would biomass emissions be calculated for purposes of compliance with the NSPS.

EPA’s response to interagency comments addressed biomass, and some of the response could be

incorporated into the preamble. For example, EPA could incorporate some of the following language:

“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 September 28, 2012[1], 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.”

[EPA Response: The proposed CO 2 emission standards would only apply to new fossil fuel

‐ fired EGUs.

New EGUs that primarily fire biomass would not be subject to these proposed CO 2 emission standards.

Such units could fire fossil fuels up to 10 percent on an annual heat input basis (e.g., for start

‐ up and

combustion stabilization) without becoming subject to the standards.

The proposed CO 2 emission standards do not apply a unique accounting method for biogenic CO 2

emissions for the purpose of determining compliance with the standards for those units that may, for

example, co

‐ fire biomass with fossil fuels. Issues related to accounting for biogenic CO 2 emissions from[Type text]



## Summary of Interagency Working Com ments on Draft Language under

EO12866 Interagency Review.  Subje ct to Further Policy Review.



## ­ EPA Response

­

5 stationary sources are currently being evaluated by the EPA through its development of an Accounting

Framework for Biogenic CO 2 Emissions from Stationary Sources.]

4. Question for background: Recognizing that this proposed rule would only require coal

‐ fired units to

transfer captured CO2 to a facility that reports through EPA’s GHG reporting program and does not

impose requirements for long

‐ term storage of CO2, would EPA have the authority to issue a

separate regulation to address emissions from the downstream CO2 storage facilities if leakage or

venting became more of a problem than EPA anticipates? (Through a separate 111 standard, for

example?)

6. Does EPA address in the preamble how existing coal units that have been converted to natural gas

units will be treated? In other words, if a coal unit is converted to a natural gas (or co

‐ firing) unit, is it

considered a “new” source that is then subject to the NSPS for new sources? It would be helpful for EPA

to explain the treatment of such sources in the rule.

[EPA Response: In the preamble we define 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.” We define a reconstruction as “the

replacement of components to such an extent that the capital costs of the new equipment or

components exceed 50 percent of what is believed to be the cost of a completely new facility.”

An existing coal

‐ fired unit that converts to natural gas

– or that co

‐ fires natural gas

– would not increase

the amount of any air pollutant or result in the emission of any air pollutant not previously emitted

....

nor would it require investment of capital costs exceeding 50% of the cost of a new facility. As such,

such a facility would not be a new, modified or a reconstructed facility. However, please note that we

have explicitly stated in the preamble that

... “At this time, the EPA is not proposing standards of

performance for modified or reconstructed sources.”]

7. “By contrast, NGCC with CCS is not a configuration that is being planned and built today. ...”

Recommend deleting “planned and” and therefore leaving as “that is not being built today.” Why? We

know of two instances where there have been corporate press announcements of “plans” to develop

NG

‐ CCS: GE

‐ Sargas and Summit

‐ Linde. If EPA has specific definitions of what constitutes “planned” that

go beyond press announcements, then this might assuage our concern.

[EPA Response: Agreed. This change has been made.]

8. “... the subpart would contain two different categories, one for utility boilers and IGCC units and one

for stationary combustion turbines.” Small technical correction: should be “stationary natural gas

combustion turbines.

[EPA Response: Agreed. This change has been made.][Type text]



## Summary of Interagency Working Com ments on Draft Language under

EO12866 Interagency Review.  Subje ct to Further Policy Review.



## ­ EPA Response

­

6 9. “Therefore, we are proposing the gross electric output for steam generating units ...” et sequelae.

EPA is clearly grappling with the concept of gross, adjusted gross, and net emission standards.

Essentially, the proposal is that steam turbines get adjusted gross (i.e., gross minus some parasitic load,

which is small) while IGCC get gross (i.e., don’t adjust for parasitic load for CCS because of the

complexity in measurement and co

‐ product manufacture). It reads a little like a bonus pass for IGCC

‐

CCS, which has quite a significant parasitic load. If power companies are designing IGCC for its benefits

and accepting the intrinsic parasitic load, then what would be the additional parasitic load for the CCS

component

‐‐ percentage?

[EPA Response: First it should be noted that EPA is taking comment on two alternative forms of the

standard, gross adjusted load and net load. There are two major sources of parasitic load associated

with IGCC technology, most of the parasitic load is in fact due to the gasification process and not the CCS

equipment. For IGCC’s, CCS has about a 4% impact on net heat rate. For PC’s, it is about 12%.

A table has been added to the preamble showing the approximately equivalent numerical standards for

gross, adjusted gross, and net

‐ output based standards.]

10. Paragraph starting: “The 2013 AEO cost and performance ...” Regarding the capacity factor

definitions here, there still seems to be some inconsistency between “supply” and “sell.” Suggest a

quick scrubbing to keep to the term in the actual rule, which is

... “sales”.

[EPA Response: We will search for these terms and edit accordingly.]

11. Paragraph starting “We are not currently considering ..” Search IGCG and replace with IGCC.

[EPA Response: Agreed. This change has been made.]

12. Footnote 237: This does not include the dispatch rate for NGCC in the table, which is important,

unless “combustion turbine” dispatch is meant to cover NGCC.

[EPA Response: The assumed capacity factor for NGCC is 85%. The footnote will be updated.]

13. “A. Best system of emission reduction. The EPA evaluated several different ...” [systems for natural

gas]. “... because of uncertainties about technical feasibility ...” Suggest changing to, as EPA does later

on, “... BSER because of insufficient information to determine technical feasibility ...”

[EPA Response: Agreed. This change has been made.]

13. “Because virtually all new fossil fuel

‐ fired power is projected to use NGCC technology, requiring CCS

would add significant costs to electricity generation across the nation ...” Suggest that EPA read this

language in the context of how it might sound 8 years hence when BSER again has to be determined for

EGUs. The EIA estimated cost for NGCC

‐ CCS is $93/MWhr, up from $63/MWhr for NGCC alone. The $93

LCOE estimate for NGCC

‐ CCS is within the range of current prices for electricity generation across the

board (wind, solar, nuclear, etc) that EPA has emphasized as supportive of requiring partial CCS for IGCC

and SCPC in this rule. It would seem that the price increase logic against NGCC

‐ CCS is contrary to a[Type text]



## Summary of Interagency Working Com ments on Draft Language under

EO12866 Interagency Review.  Subje ct to Further Policy Review.



## ­ EPA Response

­

7 major basis of the current NSPS rationale for coal. Indeed, the reason that NGCC

‐ CCS is not BSER is

because we do not have sufficient information and essentially none have been built (so it’s not BSER),

rather than there being intrinsic problems with this technology which EPA is inappropriately trying to

use as supporting rationale. Also, increasing the price of an electricity generation source, per se, is not

sufficient to reject BSER, as such a future evaluation should take into account the alternative energy

sources and the social and environmental benefits of the proposed requirement, i.e., this RIA analysis

would rightly bring in the social cost of carbon, which it has not done currently in this sentence and

statement.

[EPA Response: This comment raises several points. With respect to costs, EPA’s view is that because a

large number of new natural gas combustion turbines are expected to be constructed, the additional

costs of electricity due to full or partial

‐ capture CCS for those plants would have a significantly greater

impact nationwide than the additional costs of electricity from the few new coal

‐ fired power plants that

may be constructed. With respect to technical feasibility, EPA’s view is that not enough information is

available to determine whether partial capture CCS for natural gas combined cycle plants is technically

feasible. The limited deployment to date of natural gas combustion turbines with CCS is one reason for

the limited information. With respect to the significance of the increase in price of electricity, cost is

one criterion in the multi

‐ criteria test for determining BSER. For natural gas combustion turbines, the

costs of partial

‐ capture CCS, the lack of information to assess its technical feasibility, and the fact that

natural gas is already considered a low

‐ carbon fuel are the main reasons why EPA proposes that partial

capture CCS is not BSER for natural gas combustion turbines.]

Regulatory Impact Analysis:

14. “... and small amounts of coal with CCS supported largely by Federal and State funding). Delete

“largely.” For instance, the current capital cost of Kemper (not O&M) is around $3.8B, while the direct

DoE subsidy is ~$400M, plus tax incentives. This sentence, as written, gives a false impression of the

proportional contribution of Federal and State money to the EGUs through the term “largely,” absent a

more careful analysis of proportional contributions from Southern Corp.

[EPA Response: Agreed. This change has been made.]

Additional minor suggested changes

[EPA Response: We are working through these suggested changes and editing accordingly.]

1. Page 8

– first sentence in the supplementary information section is not needed.

2. Page 14

– consider the consistency regarding the use of “adequately demonstrated” before the

(BSER) acronym. Page 18 states “BSER adequately demonstrated”, instead of “adequately

demonstrated BSER”. Please address for consistency.

3. Page 15

– suggest adding one more sentence to round out discussion of not proposing stds for

modified or reconstructed sources.

4. Page 20

– in sentence with FN 4, add “new” before “sources covered by subpart Da”.[Type text]



## Summary of Interagency Working Com ments on Draft Language under

EO12866 Interagency Review.  Subje ct to Further Policy Review.



## ­ EPA Response

­

8 5. Page 20

– is it better to say “may” justify a separate BSER determination?

6. Page 24

– please specify what type of standard “it may propose a standard” for the coal

‐ fired

EGU. An NSPS standard specific to that unit, which presumably is not installing CO2?

7. Page 31

– Please address comment about international facilities with partial CCS.

8. Page 32

– Please add a FN noting which facilities would already meet an emission limit based on

partial CCS.

9. Page 34

– Why is it not enough to say that there isn’t sufficient information? It seems odd to

question the technical feasibility of implementing CCS at NGCC units. Is there a way to talk about the

potential for emissions reductions from CCS at NGCC units, and compare that to the cost? Or note that

there is not enough data to do such an analysis? Having one NGCC unit indicates that it is technically

feasible.

10. Page 34

– please clarify the percent involved in “a very small portion of its exhaust stream”

11. Page 35

– in added redline, need to add an “s” to “mean”.

12. Page 43

– FN 13 should include “CRR” as an abbreviation if the agency intends to later use it in

FN 35. Note FN 65 also includes full citation, yet FN 113 does not. Need to make consistent throughout.

13. Page 64

– FN 44 references a sensitivity analysis with the year 2025, but earlier in the text 2024

is referenced. Which year is accurate?

14. Page 72

– Will EPA add examples of other NSPS that do prescribe a particular technology?

15. Page 77

– omit comma after April in redline text.

16. Page 82

– there are two “of” in the 4th line; second “of” should be “if”.

17. Page 84

– Suggest EPA add another sentence explaining why CO2 emissions are the only entity

subject to the proposed standard of performance. Why not include other GHGs?

18. Page 84

– suggest EPA add FN regarding liquid oil

‐ fired CC units to provide more clarity to public.

19. Page 95

– what does “we take comment” mean on the fourth to last line?

20. Please address comments on page 96 and 104.

21. Page 128

– Redraft the following “This combined category cannot be considered a new

category”.

22. Page 132

– Please clarify with a quantity or percent what “a major component of that air

pollution” means.

23. Page 141

– change conclude to “concludes”

24. Page 179, 187, 208, and 244

– please address comments.

25. Page 227

– It does not appear that additional text was added.

26. Page 266

– Odd that the list of GHGs is placed in FN 266. Consider stating earlier.

27. Page 279

– Please address comments.

28. Page 336

– In the Impacts of the Proposed Action section, suggest adding a discussion here of

the potential impacts of the alternative co

‐ proposal

, and comparing that with the separate standards

proposal. Given that the co

‐ proposal is unlikely to alter the estimated impacts, costs, and benefits, it

may be sufficient to add a paragraph of discussion in the beginning of the Section.

i This estimate is based on internal NETL analyses and di d not originate with the demonstration project participants.

As such, it may not represent their own projections of demo project costs.[Type text]



## Summary of Interagency Working Com ments on Draft Language under

EO12866 Interagency Review.  Subje ct to Further Policy Review.



## ­ EPA Response

­

9 ii Quality Guidelines for Energy System Studies: Tech nology Learning Curve (FOAK to NOAK). NETL/DOE341/042211. March 2012.

iii Values reported by NETL are first-year, nominal dollar COEs that include a cost of $10/tonne for transport and

storage of captured CO 2 . NGCC COEs assume a delivered natural ga s price of $6.13/MMBtu. All coal plants

assume bituminous coal at a delivered cost of $2 .94/MMBtu, except for the Kemper County IGCC which uses

lignite coal.

iv NGCC COEs are based on plants that feature an advanced F-frame gas tu rbine. COEs for NGCCs with more

advanced gas turbines (H- or J-frames) would be around 5-10% less for systems without CCS and 7-14% less for

systems with 90% CCS.

v Source: Page 5, http://www.catf. us/resources/testimony/files/20120920-

Thompson_CATF_Energy_and_Power.pdf

vi This internal NETL estimate (which did not come from So uthern Company) is based on the most recent publicly

reported capital cost of ~$7,300/kW for the Kemper IG CC plant (assumed to be a total as-spent capital cost,

excluding costs for the lignite mine and CO 2 pipeline, and calculated based on the plant’s syngas-based net capacity

of ~524 MW) and the following assumptions based on generic NETL system studies: an O&M cost of $54/MWh

including fuel, a capital charge factor of 0.124, and a capacity factor of 80%.