Summary of Interagency Working Comments on Draft Language under 

EO12866/13563 Interagency Review. Subject to Further Policy Review.

1

Assumptions regarding the viability of CCS technology and Compliance Uncertainty 

 On page 61 EPA states, “at present, CCS is technologically feasible and its core components (CO2 

capture, compression, transportation and storage) have already been implemented.” Several 

commenters note that capture, compression, transportation and storage at full scale on coalfired power applications has never been implemented and that there are significant technical 

and legal barriers to achieving the level of deployment assumed by the draft proposed rule. 

In addition to the Mountaineer pilot project and the Vattenfall-Alstom oxyfuel/CCS project at 

Schwarze Pumpe in Germany, Southern Company is currently building a full scale utility CCS 

project in Mississippi. Additionally, Summit Power has announced that they are close to 

breaking ground on a full scale project in Texas. (all of the US projects are receiving financial 

support from the Department of Energy)

Analysis by both EIA and EPA suggests that with expected gas prices and electric demand, there 

will be no new coal beyond the small amounts with CCS that are receiving federal funding. Even 

if some additional coal were built, we expect that it would be in small amounts. 

Several commenters are concerned that the availability of a 30-year average alternative 

compliance option for new coal units through the use of CCS will not provide a realistic 

compliance option. The proposed rule states that “CCS technologies exist that can be readily and 

cost-effectively used to reduce GHG emissions from coal plants”. In addition, the proposed rule 

also states that emissions associated with existing plants can also be lowered by improvements 

in efficiency, dispatch order and co-firing. However, the rule also states that its implementation 

will “assist in the deployment of CCS technology for new coal-fired power plants and relate an 

incentive for the use of efficient natural gas-fired generation” and that “regulatory uncertainty 

may be hindering the development and deployment of CCS.” These statements concerning CCS 

within the proposed rule appear inconsistent. Either CCS, energy efficiency and co-firing 

technologies are readily available and cost-effective or they are not. While EPA can, under 

section 111, “look toward what may fairly be projected for the regulated future, rather than the 

state of the art at present”, it cannot do so based upon “crystal ball” inquiry.1 

As is further elaborated in both the preamble and responses below, we believe that because of 

the long lived nature of CO2 in the atmosphere, a long term averaging option could have similar 

environmental benefits. Because of the potential for future cost reductions in the 

implementation of CCS technologies, we believe some project developers may find the flexibility 

of this alternative compliance option useful.

We believe that commenters were referring to the following statement.

(page 13 of 208) The EPA is proposing to control CO2 pollution from fossil-fuelfired power plants because they are responsible for 40 percent of all U.S. 

anthropogenic GHG emissions. Individual new power plants powered by coal 

are among the largest individual new sources of GHGs. Furthermore, technology 

 

1

Portland Cement Ass’n v. Ruckelshaus, 486 F.2d 375 (D.C. Cir. 1973); International Harvester v. Ruckelshaus (D.C. 

Cir. (1973).
Summary of Interagency Working Comments on Draft Language under 

EO12866/13563 Interagency Review. Subject to Further Policy Review.

2

exists that can be readily and cost-effectively used to reduce GHG emissions 

from these sources. Thus, this proposed rule is a rational first step to control 

GHG emissions from the largest categories of stationary sources under CAA 

section 111.

In the statement “technology exists that can be readily and cost-effectively used to reduce GHG 

emissions from these sources”, we intended “these sources” to mean “fossil-fuel-fired power 

plants” and the best system of emission reduction to be natural gas combined cycle (NGCC). 

We will clarify our intention in the subsequent revision of the preamble.

 In several places, commenters have stated that the preamble mischaracterizes the CCS Task 

Force report. On Page 60, the preamble asserts “the Administration’s CCS task force report 

anticipates that CCS will become widely commercially available after 2020.” This understanding 

of the report, pervasive in the preamble is inaccurate. The second and third sentences of the 

CCS TF report represent an accurate reflection of the bottom line message of the report. “In its 

application to electricity generation, CCS could play an important role in achieving national and 

global greenhouse gas (GHG) reduction goals. However, widespread cost-effective deployment 

of CCS will occur only if the technology is commercially available and a supportive national 

policy framework is in place.” 

We will modify the preamble to address these concerns. 

 Several commenters believe it is premature for EPA to suggest that the integrated gasification 

combined cycle (IGCC) and carbon capture and sequestration (CCS) technologies it identified as 

being slated for demonstration are sufficiently mature, or have diverse enough application, for 

EPA to “fairly project their becoming commercially available” to the electric utility industry as a 

whole within the context of its 30 year average proposal. 

As further clarified in the revised preamble, this rule does not require CCS; rather, it establishes 

an emission rate for fossil fueled power plants that can be met by a natural gas combined cycle 

plant, which is identified as the best system of emission reduction that is adequately 

demonstrated for this category of sources. The standard could also be met by coal plants with 

CCS. While EPA does not predicate this proposal on CCS technologies being commercially 

available for all applications within the context of the 30 year averaging proposal; it provides an 

alternative compliance option to facilitate the implementation of CCS for those applications for 

which it will be commercially available and appropriate. Also, some projects like Southern 

Company’s are not just slated for demonstration but are actually under construction.

 One commenter notes that the only significant operating coal based power generation CCS 

project is a 20 MW slipstream project at the 1300 MW AEP Mountaineer plant in West Virginia. 

Does this constitute an “adequate demonstrat[ion]” of the “best system of emissions reduction” 

for the purposes of CAA § 111? Additionally, by combining parts of categories Da and KKKK, is 

EPA asserting that the best system of emissions reduction for a new coal power plant is in fact to 

build a NGCC power plant instead? 

As explained in the preamble, EPA is not proposing that CCS is the best system of emission 

reductions. Under the proposed combined category, the best system of emission reduction for 
Summary of Interagency Working Comments on Draft Language under 

EO12866/13563 Interagency Review. Subject to Further Policy Review.

3

a fossil-fuel fired power plant is NGCC. Any potential new fossil fuel-fired power plants covered 

by the performance standard can achieve this emissions rate any way they choose, including 

using CCS. Also, we note that there are additional projects under construction that use CCS

beyond the Mountaineer project.

 Throughout the preamble, reg text, RIA and the presentation, several planned CCS projects are 

specifically named to support the agency’s assertion of future viability. Could EPA please 

include information regarding the extent to which, and manner in which, each of these plants is 

subsidized by the state or federal government? On pages 91-92, EPA mentions the likelihood of 

additional assistance from the federal government for CCS projects. Please support this 

assertion. Additionally, one commenter asked a more general question regarding how the 

existence of significant federal subsidies was factored into EPA’s “availability” determinations 

regarding CCS. 

While EPA does not have complete financing information on all of the projects cited, we agree

that they generally include funding from Federal sources as part of their overall project finance. 

We will edit the preamble to make this clear. 

 Several commenters believe that CCS can only be declared ”commercially available” after 

carbon sequestration from coal plants has been widely demonstrated in major regional non-oil 

bearing formations using CO2 obtained from EGUs which are burning coals commonly used for 

power production in those regions. 

Most of the facilities EPA has cited in support of its CCS projection are enhanced oil recovery 

(EOR) related. For example, the CO2 produced from the Southern Companies Kemper IGCC/CCS, 

Tenaska Trailblazer Energy Center (TEC) Tenaska Supercritical Steam/CCS, Summit Energy 

IGCC/CCS/Urea, Sweeny Refinery IGCC; and Hydrogen Energy California (HECA) projects are all 

slated to be injected into well established oil fields for the purposes of EOR. While the 

information obtained from EOR may prove to be valuable as a first step towards CCS 

demonstration, the commenter does not believe that lessons learned in injecting CO2 into well 

established oil fields will provide the information necessary to demonstrate that CCS will be 

commercially available for nationwide application in power plants. With regard to the Sweeny 

Refinery IGCC plant, the commenter also notes that the feedstock to this plant is pet coke and 

not coal. Similarly, the feedstock to the HECA plant is expected to be a combination of 25% pet 

coke and 75% sub-bituminous coal. Pet coke and coal have fundamentally different 

characteristics. As a result, the commenter feels that demonstrations using pet coke feed stocks, 

either wholly or as a blend, are unlikely to produce information useful or applicable to CCS for 

gases derived from coal and/or the large variety of coals needed to sustain the national power 

grid. With regard to the Tenaska Taylorville Energy Center, Tenaska itself has stated to the 

Illinois EPA that the pollution control plan in its desired legislation approving this project is “not 

commercially available”.2 

EOR is likely to be a key component to many, if not all, of the CCS projects in the next ten to 

fifteen years. Because CO2 can be (and currently is) transported over long distances via pipeline, 

 

2

“Your View: The Dirty Truth about the Taylorville Energy Center”, Crain’s Chicago Business News, November 25, 

2011.
Summary of Interagency Working Comments on Draft Language under 

EO12866/13563 Interagency Review. Subject to Further Policy Review.

4

projects using EOR can be located throughout the country. Currently projects providing CO2 for 

use in EOR are being pursued in a number of States including Indiana, Illinois, Texas, California

and Mississippi. There is also an operating gasification plant in North Dakota supplying CO2 for 

enhanced oil recovery in Saskatchewan, Canada.

EPA believes that interagency commenters may be envisioning a much more significant use of 

CCS than is contemplated by this proposed rule. It focuses on new and reconstructed power 

plants and does not focus on the existing coal plants that provide the vast majority of the coalfired generation. The EPA agrees that there are differences in the characteristics of the coal and 

pet coke fuels used in an IGCC process. The EPA also understands that the syngases produced 

from the gasification of both fuels are fundamentally the same and the technologies used to 

treat the syngas from either fuel would be the same. Lessons learned from development of 

those projects would in fact be applicable to power plants.

 EPA has stated its purpose in the incorporation of a 30-year average as an alternative method to 

determine compliance is to encourage innovation that may or may not actually occur. As such, 

some commenters stated that it is difficult to understand how the use of a 30-year average 

would actually successfully work in practice. The technologies EPA have assumed to be available 

within the 30 year period may not be readily and cost-effectively available within the time 

projected. Under these conditions, it would seem extremely difficult--if not impossible—for any 

entity to produce a compliance plan using this alternative compliance option in a manner that 

would ensure successful financing

As commenters note, the thirty year average is an alternative compliance mechanism that EPA is 

proposing companies may use. It is not requiring the use of it. Some companies may anticipate 

that future developments in CCS will lower costs and improve performance, they may choose to 

defer deployment. 

 Page 13, Item 2: In this section, it is stated: “Individual new power plants powered by coal are 

among the largest individual new sources of GHGs. Furthermore, technology exists that can be 

readily and cost-effectively used to reduce GHG emissions from these sources”. – As noted 

earlier, this second statement refers to the use of gas-fired combined cycle generation. The 

preamble will be revised to clarify this.

o Please note that several aspects of carbon capture technologies have not been 

demonstrated yet at full-scale, fossil power plants. The overall CCS technology is also 

not presently considered cost effective for fossil plant applications, as acknowledged in 

the Preamble in several places. See pp. 97, 102-103. Therefore, the statement that CCS 

can be readily and cost effectively used to reduce GHG from fossil sources is highly 

questionable. One commenter also noted that the cost-effective statement appears to 

be at odds with the Administration’s monetized value of the social cost of carbon.

o Commenters also suggested this statement is at odds with EPA’s position included in the 

GHG BACT guidance, which was published in March 2011. This guidance document 

contains the following statement on CCS technical feasibility: “While CCS is a promising 

technology, EPA does not believe that at this time CCS will be a technically feasible BACT 
Summary of Interagency Working Comments on Draft Language under 

EO12866/13563 Interagency Review. Subject to Further Policy Review.

5

option in certain cases. As noted above, to establish that an option is technically 

infeasible, the permitting record should show that an available control option has 

neither been demonstrated in practice nor is available and applicable to the source type 

under review. EPA recognizes the significant logistical hurdles that the installation and 

operation of a CCS system presents and that sets it apart from other add-on controls 

that are typically used to reduce emissions of other regulated pollutants and already 

have an existing reasonably accessible infrastructure in place to address waste disposal 

and other offsite needs.” BACT guidance, p. 36. How does EPA reconcile the positions 

in the BACT guidance and the statements in the Preamble? 

The guidance, on p. 20-21, explains that ... “As of the date of this guidance, EPA has not 

promulgated any NSPS that contain emissions limits for GHGs. ... To the extent EPA 

completes an NSPS for a relevant source category, BACT determinations that follow will 

need to consider the levels of the GHG standards and the supporting rationale for the 

NSPS.” It further explains, on p. 32, that ... “For the purposes of a BACT analysis for 

GHGs, EPA classifies CCS as an add-on pollution control technology that is available for 

facilities emitting CO2 in large amounts, including fossil fuel-fired power plants .... “. 

Finally, the cited language was written to address the BACT analysis for the entire broad 

range of facilities subject to PSD – not just of fossil-fired EGUs and reflects the fact that 

the BACT analysis is specific to the particular permit at issue. Accordingly, since BACT is 

determined on a case-by-case basis, the above statement from the BACT guidance is 

only acknowledging that CCS will not be technically feasible “in certain cases.” The 

BACT guidance does not say that CCS will never be technically feasible. Perhaps most 

importantly, this NSPS applies only to new construction, and not modifications.

o Several commenters expressed concern about the Proposed Rule’s statements about 

CCS, and the proposed standards and alternative compliance option because of their 

implications on BACT. As EPA’s BACT guidance states, “The CAA specifies that BACT 

cannot be less stringent than any applicable standard of performance under the New 

Source Performance Standards (NSPS)... To the extent EPA completes an NSPS for a 

relevant source category, BACT determinations that follow will need to consider the 

levels of the GHG standards and the supporting rationale for the NSPS.” BACT guidance, 

p. 20. The guidance indicates that CCS is a promising technology but “EPA does not 

believe that at this time CCS will be a technically feasible BACT option in certain cases.” 

BACT guidance, p. 36. The statements EPA makes regarding CCS and the 

standards/alternative compliance option EPA adopts under NSPS will have effects on 

BACT; therefore, it’s important that EPA’s conclusions are consistent and wellsupported. 

See response above. 

 Page 18, 2nd Paragraph: It is stated: “Coal-fired power plants with CCS are being permitted and 

built today.” Commenters suggested that EPA should clarify in this section that the only CCS 

plants being built are being done so with significant government incentives. Therefore, these 

installations may not address the cost effectiveness issue related to CCS. 

We will clarify in the revised version of the proposal.
Summary of Interagency Working Comments on Draft Language under 

EO12866/13563 Interagency Review. Subject to Further Policy Review.

6

 Page 19: It is stated: “The proposed rule will assist the deployment of CCS technology for new 

coal-fired power plants and create an incentive for the use of efficient natural gas-fired 

generation. Regulatory uncertainty may be hindering the development and deployment of 

CCS.” Although this statement is true, inclusion of a GHG limit on new power plants may not 

incentivize new CCS builds, as no rate recovery structure is in place to offset the added capital 

and decreased power output borne by the plant with the inclusion of CCS. Deployments prior to 

the availability of cost effective CCS systems will likely only be possible with government 

support. 

As demonstrated by the fact that AEP has put future phases of its Mountaineer CCS project “on 

hold until such time that economic and policy conditions create a viable path forward”3, in many 

places utility regulators may not authorize recovery of the costs of implementing CCS unless and

until regulatory requirements are in place that can be met through CCS. Therefore, a regulatory 

requirement can help to incentivize new CCS builds. We agree that, at least in the short term, 

federal incentives are likely to be necessary. 

 On page 89, EPA notes that although a small number of new coal-fired power plants have been 

built recently, the industry generally is not building these kinds of power plants at present and is 

not expected to do so for the time being. The reasons include the current economic 

environment, which has lead to lower electricity demand; and competitive natural gas prices.

Low electricity demand may only be a function of the current position of the economic cycle 

(the bust, as opposed to the boom). It may be temporary and may not last. Has EPA considered 

a scenario with improvements in the present economic conditions? 

See attached analysis where we have examined a higher electricity demand scenario designed 

to simulate improved economic conditions.

 Also on page 89, EPA notes that natural gas prices have stabilized over the past few years as 

new drilling techniques have brought additional supply to the marketplace. As a result, natural 

gas prices are expected to be competitive for the foreseeable future and utilities are likely to 

rely heavily on natural gas to meet new demand for electricity generation. – See attached 

analysis on higher gas price scenario.

o Gas prices may not always remain low, and future prices may not continue to reflect the 

recent past. This is an example of a vividness bias (projecting the immediate past into

the distant future; overestimating the likelihood of certain events based on very 

memorable data or experiences, in this case, low domestic gas prices and the recent 

dramatic increase in domestic gas production). Assumptions about future gas prices in 

the analysis are not based on consideration of the immediate past but rather on 

projections of natural gas resource bases and estimated recovery costs.

o In addition, natural gas prices in China are roughly four times higher than the U.S. spot 

price of $4/mcf, and there is every reason to believe that the U.S. will become a global 

exporter of gas. Aubrey McClendon, CEO of Chesapeake Energy, has already pledged to 

supply gas to the Sabine Pass LNG export terminal in Louisiana. There is no reason to 

 

3

 http://www.aep.com/environmental/climatechange/carbon/capture/
Summary of Interagency Working Comments on Draft Language under 

EO12866/13563 Interagency Review. Subject to Further Policy Review.

7

believe that if global demand is commanding a higher price, domestic producers will not 

supply the gas. All things equal, as a world market for gas continues to develop, world 

prices may converge, suggesting upside pressure on current U.S. prices. 

Currently, both EPA and EIA projections show that when higher natural gas prices are 

assumed, no new coal is expected to be built in the 2020 time-frame. 

o The Sabine Pass facility, which was originally intended as an LNG import project but now 

sits mostly idle, will require $6 billion in upgrades to convert to an export facility (at 

which point the export potential will be 2.6 bcf/day). At the current Chinese gas price of 

approximately $16/mcf, it will take less than 5 months to pay off the cost of the export 

conversion. This global trade represents a tremendous potential market for domestic 

producers, and there is a very strong possibility that, without legislation expressly 

preventing gas exports, domestic gas prices will be driven up to global levels. See 

response above.

Emissions Limit 

 Page 21, 1st Paragraph: This paragraph lists the CAA Section 111 requirements pertaining to the 

establishment of a standard of performance for CO2 emissions from EGUs. Cost and adequate 

demonstration are two important considerations mentioned for the best system of emission 

reduction selected. Several commenters have suggested that it appears that these two 

considerations have not been adequately addressed in the preamble for the CCS technology 

selected as the best system of CO2 emission reduction to achieve the 1,000 lb/MWh limit for 

coal-fired units. As explained above, we are not proposing in this rule that CCS is the best 

system of emissions reduction.

 Pages 89, Section 3: EPA’s rationale for establishing an emission limit is based on an assumption 

that only a few coal-fired power plants will be constructed in the foreseeable future. However, 

if EPA’s assumption is true, this rule may not be justified on the basis of any environmental 

benefit, since installation of CCS on a few plants will not achieve any significant amount of CO2

reduction. In the summary section on Page 1, EPA cites fossil power plants being the largest 

source of GHG emissions as the main reason for proposing this rule. However, if EPA does not 

expect any notable CO2 emission changes (see Page 155) from this rule, use of the potential 

addition of only a few new power plants in the foreseeable future as a rationale for proposing it 

may not be justifiable. Since this section specifically addresses the rationale for this rule, the 

commenter suggests that it be revised to present a more relevant rationale. EPA believes there 

are multiple policy rationales for this rule. The power sector is the largest single stationary 

source category of CO2 emissions. Developing an NSPS for new sources is the obvious first step

and can also ensure that resources are not “stranded” in new high-emitting generation that 

makes future GHG reductions more expensive. Furthermore, this rule could help incentivize 

technology development that could be used both in the US and exported abroad. 

o Pages 92-95: EPA has presented the methodology for developing the 1,000 lb/MWh 

CO2 emission limit, based on information available for different combined cycle 

configurations. Commenters agreed with the different performance adjustment factors 

EPA has used for a combined cycle plant. However, they note that the rule covers a 

variety of combined cycle applications (e.g., duct burners and distillate oil firing) and 
Summary of Interagency Working Comments on Draft Language under 

EO12866/13563 Interagency Review. Subject to Further Policy Review.

8

configurations, which are not all covered by the adjustments discussed on these pages. 

Therefore, they have requested a copy of the analysis EPA has performed in establishing 

the above emission limit for review and further comments. They also point out the 

following fossil-fueled combined cycle design considerations that are apparently missing 

from the performance adjustments cited by EPA: EPA has performed an additional 

analysis looking at data from all natural gas-fired combined cycle units built from 2006 

to 2010 used in the power sector that are not cogenerating and that report complete 

generation data to the Agency. Based on this analysis, nearly 95% of units built 

between 2006 and 2010 meet the proposed standards on an annual basis. These units 

represent a wide range of geographic locations (with differing elevations and ambient 

temperatures), operational characteristics and sizes. This analysis was transmitted to 

OMB (on 1/25/2012) 

o The variability in the natural gas carbon content is one of the factors that affect CO2 

emissions from a combined cycle plant. We reviewed the available variability data and 

found that the carbon content can vary as much as 10%. Therefore, we suggest that 

EPA address this factor in its analysis for establishing the CO2 emission limit. Since the 

standard is based on a 12-month average any short periods of natural gas with higher

carbon content should be balanced out with periods of lower carbon content natural 

gas. It is our understanding that mixing of propane and higher chain hydrocarbons are 

primarily used for periods of high natural gas demand and not on a regular basis. If 

commenters have additional data on this issue, we are happy to consider it. 

o In the performance adjustment factors used by EPA, adjustments have been made only 

to the heat rate of a combined cycle unit. Please note that most of the adjustment 

factors shown in the preamble also have reductions in the MW output capacities. This 

reduction in the gas turbine output has a corresponding increase in the CO2 emissions in 

lb/MWh. For example, with the plant performance degradation, not only is there an 

increase in the heat rate of 5%, but there is also a reduction in the output of 5%. – See 

analysis noted above.

o The adjustment factors used by EPA do not include an adjustment for the plant 

elevation above sea level. If there is a potential for industry to switch from coal to gas 

firing, installation of these gas plants throughout US, including at high elevations, must 

be considered. The net effect of a high elevation is a reduction in the gas turbine 

output, without a change in the fuel consumption. As much as 17% output reduction 

has been reported at 5,000 foot elevation for some GE machines. As noted above a 

reduction in output at higher elevations reduces the amount of fuel that can be 

combusted (i.e., the capacity of the turbine), but should not significantly impact the 

heat rate of a combined cycle facility. The analysis noted above, which includes units 

located at a wide range of altitudes, appears to support not making any adjustment for 

elevation.

o EPA has used a 5% performance penalty for part load operation. Following EPA’s 

assumptions of more renewables and gas-based plants being installed in the foreseeable 

future, it can be expected that many of the gas-based plants would operate in support 
Summary of Interagency Working Comments on Draft Language under 

EO12866/13563 Interagency Review. Subject to Further Policy Review.

9

of the renewables and thus be subjected to frequent cycling and low-load operation. A 

5% performance penalty does not appear to be sufficient for this type of operation. 

With the current designs, the turndown capability for large gas turbines is 35% and for 

smaller machines is 50%. The performance penalty at 35 and 50% loads can be as high 

as 35% and 18%, respectively . These figures suggest that an adjustment factor higher 

than 5% may be warranted, if a more frequent low-load operation regime is assumed. 

The main concern we have is that, if a more conservative mode of operation is not 

selected, it may not be possible for the industry to utilize a combined cycle unit for 

many future applications. – See analysis noted above that shows that a wide range of 

units operated in a variety of ways were able to meet the proposed standard on an 

annual basis.

o The rule covers all fossil-fired combined cycle configurations. With the expected 

widespread use of gas-fired units, the potential for a specific unit to require distillate oil 

as a standby fuel to fire during periods of gas curtailment does exist. However, 

depending on the frequency of oil firing, the CO2 emission would exceed the proposed 

1,000 lb/MWh and the 1,100 lb/MWh limit which is the high end of the range being 

considered by EPA. – Gas curtailments are usually short term in nature and the 

standard allows for annual averaging. This allows any periods of higher CO2 emissions to 

be averaged out. 

o The rule explicitly mentions combined cycle units equipped with duct burners. 

However, the use of a duct burner has apparently not been taken into consideration in 

establishing the CO2 emission limit. A combined cycle unit gains additional MW output 

with duct burners, but the heat rate goes up substantially. One source lists an increase 

of 9% for the heat rate, with a corresponding increase of 28% in MW output. The best 

identified technology is a natural gas-fired combined cycle unit without duct firing. If 

new facilities wish to take advantage of duct firing there are several options. First, there 

are available designs that would allow continuous use of the duct burners and still be in 

compliance with the proposed standard. Second, a new facility could integrate an 

industrial turbine and use it in a complementary firing mode instead of using

supplemental firing. Complementary firing has a lower increase in heat rate than 

supplemental firing. Further, the analysis cited above shows that almost all combined 

cycle units (including those with duct burners) built since 2006 are able to meet the 

standard.

 Since the rule applies to units with capacities above 25 MW, the CO2 emission limit should 

consider small units, e.g., General Electric’s (GE’s) LM2500 PE model, that may be used by 

the industry. According to the Gas Turbine World 2011 Performance Specifications, there 

are several different options for using the LM2500 turbine engine in a combined cycle 

facility. Using the analysis described in the preamble, the LM2500PE combined cycle using 

water injection for NOx control would not be under the proposed standard. However, the 

combined cycle facility using the dry low emissions (DLE) LM2500PE combustion turbine 

engine would maintain emissions below the proposed standard.
Summary of Interagency Working Comments on Draft Language under 

EO12866/13563 Interagency Review. Subject to Further Policy Review.

10

 Page 62, Section C.1: It is stated: “In establishing the level of the proposed NSPS, the EPA 

has taken into account startup and shutdown periods. EPA is not proposing different 

standards for those periods.” 

o Based on the overall discussion in this section, EPA believes that the effect of including 

the startup and shutdown will be minimized since the overall emission compliance is 

based on a 12-month rolling average. However, since no electrical power is being 

generated during the major parts of startup and shutdown periods and the emission 

limit is in lb/MWh, any CO2 emissions with no credit for MW generated during these 

two periods will only make it more difficult for facilities to comply with the proposed 

limit. With more renewables coming on line, we expect increased cycling operation for 

the fossil-based facilities. As the number of startups and shutdowns increase, the 

adverse effect of including startup and shutdown in the compliance period will increase 

as well. In addition, this assumption seems inconsistent with the treatment of startup 

and shutdown in EPA’s almost finalized EGU MACT rule. Differing treatment of startup 

and shutdown seems just as logical here, in that those periods could have an 

unavoidable impact on emissions rates, just as in the air toxics case. In comments 

received on the EGU MACT rule, commenters suggested two ways to address 

startup/shutdown concerns. One was to set different standards for startup/shutdown, 

a second was to set longer periods over which to determine compliance with the 

standard. Because of the acute nature of toxics, EPA did not believe longer periods

were appropriate. Here, the long-lived action of GHGs support a longer period and the 

proposal takes that approach. The analysis of combined cycle units built since 2006, 

shows that these standards can be met with including periods of startups and 

shutdowns.

 Pages 89, Section 3: EPA’s rationale for establishing an emission limit is based on an 

assumption that only a few coal-fired power plants will be constructed in the foreseeable 

future. However, if EPA’s assumption is true, this rule may not be justified on the basis of 

any environmental benefit, since installation of CCS on a few plants will not achieve any 

significant amount of CO2 reduction. In the summary section on Page 1, EPA cites fossil 

power plants being the largest source of GHG emissions as the main reason for proposing 

this rule. However, if EPA does not expect any notable CO2 emission changes (see Page 

155) from this rule, use of the potential addition of only a few new power plants in the 

foreseeable future as a rationale for proposing it may not be justifiable. Since this section 

specifically addresses the rationale for this rule, we suggest that it be revised to present a 

more relevant rationale. –see response above

 Pages 92-95: One commenter performed a rough analysis to evaluate certain gas turbine 

models available from prominent suppliers (GE and Siemens) using the adjustment factors 

mentioned in the comment above and found that the CO2¬ emissions exceeded both the 

proposed 1,000 lb/ MWh limit and 1,100 lb/ MWh limit, which is the high end of the range 

being considered by EPA, in certain cases. For example, using GE’s LM2500 PE gas turbine in 

a combined cycle mode, the CO2 emissions for adjusted gross output and heat rate is closer 

to 1,200 lb/MWh. – see response above
Summary of Interagency Working Comments on Draft Language under 

EO12866/13563 Interagency Review. Subject to Further Policy Review.

11

Are there NGCC units that exceed the 3,000 hour threshold but EPA anticipates might have trouble 

meeting the 1,000 lb/MWh based on load/usage characteristics? Only 3 of the 1817 simple cycle 

turbines listed in EPA’s database operated more than 3,000 hours in 2008. These 3 turbines operated 

about 4,000 hours. 

Alternative Compliance 

Note: To address specific comments and other related comments from the interagency group on this 

topic, we are editing the preamble and the proposed regulatory text to clarify how the alternative 

method would work in practice.

o Page 56: The Proposed Rulemaking sets forth an “alternative compliance option.” It 

explains why EPA thinks this is a reasonable option, but we do not see any explanation 

of the legal basis for establishing “an alternative compliance option” in lieu of a 

standard, which is what is contemplated by the statute. What is the legal basis/support 

for establishing “an alternative compliance option”? Has EPA established alternative 

compliance options in other NSPS rulemakings? Does EPA think that an “alternative 

compliance option” would have the same regulatory effect as an NSPS standard, both 

under NSPS and BACT? The legal basis is explained on page 116 (section V.A.3(d)(2)). 

EPA has not taken this approach in other NSPS, but as explained in the preamble 

believes it is both appropriate and legal. 

o Page 57, 1st Paragraph: This paragraph establishes an alternative CO2 emission limit of 

1,800 lb/MWh, based on the use of supercritical PC and IGCC technologies. Has EPA 

performed an analysis to ensure that this CO2 limit can be met by current supercritical 

PC and IGCC technologies with net electrical outputs of 25 MW and higher? Please 

provide a copy of this analysis for review. The commenters have expressed the 

following concerns with the validity of this emission limit: The supercritical steam 

turbines are available only in sizes of approximately 200 MW and higher. Since this rule 

applies to all units above 25 MW, the smaller units <200 MW) may not meet the 

specified emission limit and may stop being available as an option for use by the power 

industry. We are continuing to evaluate this comment and some potential paths 

forward.

o In a recent DOE/NETL study, the CO2 emissions from PC and CFB boiler plants were 

evaluated for low-rank coals . This study shows that CO2 emissions on a gross output 

basis exceed the 1,800 lb/MWh limit for all plants firing lignite and using supercritical 

and ultra-supercritical designs. These plants are all over 500 MW in size. If the inherent 

reduction in efficiency for smaller plants is considered, the emission limit for western 

coal-fired plants would also exceed the 1,800 lb/MWh limit. This study did not cover all 

of the ambient factors existing in the US. If an evaluation is performed utilizing 

conservative factors, the potential exists that the emission limit of this rule may be 

exceeded for most coal types and many plant configurations. We believe that with coal 

drying technology, which is being used on a number of power plants today, the 1,800 

lb/MWh standard is in fact achievable by a wide range of units firing a variety of coal 

types including lignite. The NETL design studies evaluate lignite-fired EGUs that burn 

raw lignite without any drying/upgrading. There are multiple vendors that offer 

processes to upgrade lignite to a heating value that is equal to or greater than 
Summary of Interagency Working Comments on Draft Language under 

EO12866/13563 Interagency Review. Subject to Further Policy Review.

12

subbituminous coals. If we assume that upgraded lignite is used in the NETL design 

studies, then they would be in compliance with the 1,800 lb/MWh standard. 

Furthermore, there are a dozen bituminous-fired and 2 subbituminous-fired EGUs that 

have demonstrated the proposed annual standard is achievable on a long term basis. 

The best performing subbituminous-fired EGU has maintained a 12-month emissions 

rate of 1,730 lb CO2/MWh. A new EGU using a similar design would be able to burn 

upgraded lignite and be incompliance with the proposed annual standard.

 Page 61: “Because we expect CCS technology to advance over the next several years, we believe 

that it may not be necessary to include this type of alternative compliance option for a 30-year 

average the next time we review this NSPS.” Based on the scenario provided that some plants 

could wait to commence construction until after 2020 and still meet the 30-year average, it 

seems that consideration of terminating the alternative option in 2020 with flexibility only for 

those that have commenced construction prior to 2020 would create problems for those who 

planned construction after 2020, according to the above hypothetical. Will facilities that are 

already making plans under the 30-year average option be “grandfathered” such that they will 

not be forced to potentially accelerate their installation of controls based on a 2020 revised 

standard? EPA would address this question at the time a new standard was proposed, 

however, because we recognize the very issue that the commenter is raising, it is important to 

alert potential project developers that they should not just assume that it will be available.

 The preamble notes that the proposed NSPS would not allow emission trading or averaging 

across sources. Can EPA comment on their statutory authority to employ in this rule these 

policy tools, or other policy tools that provide flexibility in achieving compliance (e.g., offsets, 

safety valves)? In light of the fact that GHGs are a global pollutant, flexible policy tools such as 

trading or averaging should be able to achieve the same environmental benefit at lower cost. 

Further, use of such flexible mechanisms in this proposed rule could signal that flexible, costeffective approaches will generally be used in regulating GHGs from stationary sources. Are 

these options not being proposed because of lack of statutory authority or for some other 

reason(s)? If the latter, can EPA discuss why these policy tools are not proposed, or at least 

raised in the preamble with a solicitation for comments? - already covered in previous 

discussions with OMB staff

 Does EPA have the authority in the new source NSPS standards to allow trading or averaging 

among units in the same category? What opportunities for trading/averaging has EPA 

considered and why is it electing not to propose these mechanisms or take comment on them? 

Could EPA legally provide compliance credit as an incentive for retirement of GHG-intensive 

generation? - see above

 The preamble (pg. 114) says that “supercritical and ultra-supercritical boilers have CO2 

emissions of approximately 1,800 lb/MWh.” If this is the approximate rate achieved by these 

units, will companies be able to bank on their ability to perform better than this level to meet 

the immediate standards for alternative compliance option (30-year averaging to phase in CCS)? 

- See response above

Transitional Sources 

 EPA specifies that it is not proposing a standard of performance in this rulemaking for 

transitional sources that commence construction within 12 months of this proposal. However, 
Summary of Interagency Working Comments on Draft Language under 

EO12866/13563 Interagency Review. Subject to Further Policy Review.

13

transitional sources that do not commence construction within 12 months of this proposal 

would be treated as any other affected source that commences construction after the date of 

proposal of this rulemaking and thus would be subject to the new standards that EPA finalizes 

with this rulemaking. Several commenters request further explanation behind the EPA’s 

selection of a 12 month time window for required commencement of construction. For 

example, if the standards change between proposal and finalization (i.e., the alternative method 

gains traction and is applicable), this may impact plant design decisions, and final regulations 

will not be known for some time after the proposed regulation. It should also be recognized 

that some plants, namely the CCS demonstrations, are more complex and first-of-a-kind systems 

that generally are more difficult to engineer. Equipment vendors may need more time to 

provide guarantees on specific pieces of equipment that have not been used in this setting, 

hence delaying construction times. Additional consideration should be given to these projects, 

as they are critical to proving the viability of CCS. Therefore, EPA should consider a longer 

transition period for these sources with the period beginning from the date of the final rule 

promulgation would be more appropriate. As discussed with OMB staff, we believe this 

provides sufficient time to commence construction for transitional sources, which only include 

those sources that already have final PSD permits. Because they already have PSD permits and

would not be subject to new source limits, there would be no impact on design decisions that 

could require more time.

 Have each of the planned coal-fired power plants in the pipeline (that EPA is knows about, 

including latest EIA information) received air quality permits? In other words, are there any new 

coal-fired units proposed or otherwise under development that would not meet EPA’s definition 

of a “transitional source”? If so, at what stage of development are those units? Can EPA please 

further explain its rationale for regulating transitional sources under Clean Air Act section 

111(d)? EPA is still looking into this issue.

Modified Sources 

 EPA states “the EPA is not aware that any affected sources may be expected to take actions that 

would constitute “modification” (as defined under the EPA’s regulations) and therefore be 

subject to requirements for new sources”. Two noteworthy items are EPA’s definition of 

“modification” under this proposed EGU GHG NSPS and the expectation that EPA will be 

informed of all anticipated modifications at EGUs throughout the United States.

o The terms “modification” and “major modification” have been well-defined by the 

courts under New Source Review. If a source triggers a major modification under NSR 

that source is considered a “new or modified source” and is subject to new and 

modified source regulations. Rather than deviating from these definitions under the 

EGU GHG NSPS, EPA should consider treating new, reconstructed, or major 

modifications in the same consistent manner as NSR. Attempting to exempt major 

modifications from the EGU GHG NSPS while including new and reconstructed sources 

may add confusion and be interpreted as inconsistent with other EPA regulations. –

There are already differences in the way modification is defined under NSPS and NSR, 

under NSPS it is based on an hourly emissions increase, while under NSR, it is based on 

an annual emissions increase. We will review the language for clarity.

o Although EPA is unaware of “any affected sources that may be expected to take actions 

that would constitute a “modification” it would seem prudent for EPA to include 
Summary of Interagency Working Comments on Draft Language under 

EO12866/13563 Interagency Review. Subject to Further Policy Review.

14

modification provisions within the EGU GHG NSPS. Modifications can occur in addition 

to normal operation and maintenance or they can occur when the economics of an EGU 

dictate. The operation, maintenance, and planned modifications of EGUs are often 

confidential business information, it would be unlikely for EPA to be apprised of all 

anticipated modifications at all EGUs throughout the country. Within the 8-year period 

of this NSPS (2012-2020) there will likely be major modifications (boiler tubes, 

reheaters, condensers, etc.) to the aging EGU fleet that could increase maximum hourly 

emissions and/or annual hourly availability. EPA should consider including provisions 

for dealing with modified sources that are consistent with other EGU regulations. – EPA 

is considering this comment.

 Is it possible that efficiency improvements to a generating unit could potentially trigger 

“modification” requirements if those improvements led to greater use of that unit, or would 

efficiency improvements be on safe ground because they would not increase maximum 

emission rates? If an efficiency improvement does not increase hourly emissions, it would not 

trigger the NSPS modification definition.

 The pollution control exemption seems to apply for the use of a system or device “whose 

primary function is the reduction of air pollutants” (pg. 48)? Would that exemption apply for 

installation of technology to meet the 316b cooling water intake standards? Does EPA have 

data to indicate whether installation of such technology to meet 316b requirements could 

trigger application of requirements for “modifications”? EPA does not anticipate that

technologies or practices used to meet the 316b requirements will increase hourly CO2

emissions.

Existing EGUs 

 Can EPA elaborate on how this NSPS, once finalized, may influence the regulation of existing 

sources (under Section 111(d) of the CAA)? For example, does the use of a single source 

category in this NSPS imply that states will need to develop plans for reducing CO2 emissions 

from existing sources based on this same single source category (as opposed to either multiple 

categories covering the same sources or broader categories that encompassed additional 

sources)? If a version of the NSPS is finalized in which emission trading and/or averaging across 

new sources is not allowed, would these tools or policies nevertheless be available for 

regulation of existing sources? Are there examples of other pollutants regulated under section 

111(d) of the CAA? Once we have established new source provisions, we would be obligated to 

develop existing source guidelines. We do not believe the new source rule forecloses different 

approaches, in existing source guidelines, to categorization or concerning trading or averaging. 

EPA has established guidelines for total reduced sulfur under 111(d). 

 The proposed rule does not include standards of performance for existing EGUs. While the 

decision to delay provides continued uncertainty for these units, the commenter supports EPA’s 

decision to promulgate emission guidelines for states to develop plans reducing CO2 emissions 

from existing fossil-fuel-fired EGUs at a later date. No response necessary

 The commenter is supportive of EPA’s conclusion that “affected EGUs that undertake physical or 

operational changes that increase their maximum achievable hourly CO2 emission rate will be 

treated as existing sources and therefore will not be subject to any standards of performance 

we finalize for new sources, but will be subject to requirements for existing sources that we 

intend to promulgate through a separate rulemaking and that states will be required to 

incorporate into state plans”. No response necessary.
Summary of Interagency Working Comments on Draft Language under 

EO12866/13563 Interagency Review. Subject to Further Policy Review.

15

 Page 160, 2nd Paragraph: This paragraph appears to contain language exempting stationary 

combustion turbines (both simple and combined cycle-based) operating less than 3,000 hours 

annually from the requirements of this rule. It also appears that the 3,000 hour limit is related 

to the potential electric output of the plant. However, the language used is not clear and the 

type of units being exempted and the relationship between operating time limit and potential 

electric output is not clear as well. We also question the use of 50% efficiency, since it cannot 

be achieved by a simple cycle turbine. We suggest revision of this paragraph to clarify all of the 

above issues. The 3,000 hours is based on permit restrictions, we will make sure this is clear in 

the preamble. We will amend the proposal to address concerns about the 50% efficiency.

Clean Air Act Flexibility 

 Several commenters believe that EPA’s proposal to combine categories may not be supported 

by the statute. EPA relies on a parenthetical insertion in Section 111(b)(1)(A) to justify its 

combining Subpart Da and Subpart KKKK categories into a new subpart numbered TTTT. Under 

Section 111(b)(2), Congress instructed EPA to create discrete categories and gave EPA the 

discretion to distinguish among classes, types, and sizes within categories for purposes of 

establishing standards for new sources. Such discretion to sub-categorize sources was granted 

to EPA so that it could ensure that standards were set at levels that were achievable by all 

sources within a category, taking into account the nuances that may exist even between sources 

within the same category. The aggregation of categories where there is discretion to sub-divide 

would appear to be contrary to statutory intent. As explained on page 75 of the preamble 

(section V.A.1.) of preamble, EPA believes combining categories is appropriate.

 In addition, the commenter finds it curious EPA has not combined the Subpart Da and Subpart 

KKKK categories for any pollutants other than GHGs (i.e. for conventional pollutants). EPA has 

retained separate categories for conventional pollutants “because although coal-fired EGUs 

have an array of control options for conventional pollutants to choose from, those controls 

generally do not reduce their conventional emissions to the level of conventional emissions 

from natural gas-fired EGUs.”4Yet, the emission achievability rates provided by EPA in the 

preamble indicate that similar disparities exist in regard to the boilers and NGCC facilities: 1,800 

lbs CO2/MWh for coal-fired facility as opposed to 1,100 lbs CO2/MWh for NGCC.5 While coalfired boilers with CCS can achieve similar levels of GHG emissions as combined cycle gas boilers, 

they cannot achieve similar levels of other emissions with controls (e.g. SO2 with scrubbers, NOx 

with SCR).

 EPA argues in its proposal its action to combine the Subpart Da and Subpart KKKK categories in 

this way “does not foreclose construction of new coal-fired EGUs because it is feasible to control 

CO2 emissions from new coal-fired unites to levels typically achieved by new gas-fired units.” As 

discussed above, the commenter believes it is premature for EPA to suggest that the integrated 

gasification combined cycle (IGCC) and carbon capture and sequestration (CCS) technologies it 

identified as being slated for demonstration are sufficiently mature, or have diverse enough 

application, for EPA to “fairly project their becoming commercially available” to the electric 

utility industry as a whole within the context of its 30 year average proposal. See above

 

4

See EPA Proposal, pp. 79-80.

5

Id. pp. 57.
Summary of Interagency Working Comments on Draft Language under 

EO12866/13563 Interagency Review. Subject to Further Policy Review.

16

 Page 21, 1st Paragraph: This paragraph lists the CAA Section 111 requirements pertaining to the 

establishment of a standard of performance for CO2 emissions from EGUs. Cost and adequate 

demonstration are two important considerations mentioned for the best system of emission 

reduction selected. It appears that these two considerations have not been adequately 

addressed in the preamble for the CCS technology selected as the best system of CO2 emission 

reduction to achieve the 1,000 lb/MWh limit for coal-fired units. As explained in the preamble 

and noted above, EPA is not defining CCS as the best system of emission reduction in this action.

Fuel-Neutral Standard Rationale 

 Page 25, Section 5.b: The fossil-fuel-fired EGUs are stated to include coal-, coal refuse-, and petcoke-fired boilers and IGCC units. Please advise if other cofired fuels (solid, liquid, or gas) will be 

considered along with the main solid fuels. For example, if a PC plant elects to meet the 

alternative 1,800 lb/MWh limit by cofiring a small amount of natural gas, would it be 

permissible. Cofiring of biomass may also be considered. How would potential life-cycle CO2 

emission savings associated with the use of biomass be considered in this rule? - Co-firing 

natural gas would be an allowable strategy. With regard to biomass, EPA is still developing a 

biomass policy. The limits in this proposal did not consider biomass. We are adding a 

description of the process the agency is currently undertaking to address biomass for GHG 

emission reductions.

 Several commenters note that while EPA has provided extensive comment in other sections 

about the justification for its decision to utilize a fuel-neutral NSPS standard, it has not provided 

an explanation as to why it chose not to include other flexibility options that may be available in 

in the context of the “best system of emission reduction” under CAA section 111(a)(1). While 

EPA has explained other portions of the proposed rule at length in Section IV, there is no specific 

discussion of this issue in the draft rule. – See response above

 One commenter requests that EPA expand on its rationale for proposing a GHG NSPS for coal 

plants and NGCC plants, but not for natural gas combustion turbines, considering a new 

combustion turbine would be the only fossil fuel burning EGU that is not covered by this rule 

making. – Peaking turbines only account for small amounts of GHGs; this rule focuses on more 

frequently operated and higher emitting plants. 

 Page 27, 1st Paragraph: It is stated: “These increases in CO2 emissions will be small and will 

occur as a chemical byproduct of the operation of the control equipment.” Please note that 

CO2 emissions will also increase as a result of the increased auxiliary power loads associated 

with the installation of add-on controls. Because NSPS modifications focus on the unit and not 

the plant and focus on hourly emissions and not annual emissions, EPA believes that auxiliary 

power needs generally result in less hourly generation from a given unit, but not greater mass 

emissions.

 Page 89: Recommend changing the following sentence, located near the bottom of this page, 

from “At present, the cost of generation from a new NGCC power plant is lower than the cost of 

generation from a new coal-fired power plant” to something such as “On average, the cost of 

generation from a new NGCC power plant is expected to be lower than the cost of generation 

from a new coal-fired power plant.” The source note for this sentence points to EIA’s projected 

levelized costs from the Annual Energy Outlook 2011 for new plants entering service in 2016. 

The proposed changes to this sentence in the Preamble reflects language used in Chapter 5 of 

the Regulatory Impact Analysis (third paragraph). Will edit the preamble to make clear that 

while it is generally true, it is not necessarily true in every circumstance.
Summary of Interagency Working Comments on Draft Language under 

EO12866/13563 Interagency Review. Subject to Further Policy Review.

17

 On page 89, EPA notes that, “At present, the cost of generation from a new NGCC power plant is 

lower than the cost of generation from a new coal-fired power plant.” The commenter notes 

that the cost of gas generation is highly dependent upon fuel price. If the U.S. does end up 

being a gas exporter (driving up prices) and there is a heavy reliance in the US power industry on 

gas, the net effect will be higher domestic electricity prices. As explained above, EPA has done 

sensitivity analysis looking at higher gas prices.

o EPA should acknowledge emissions control technologies beyond just carbon capture 

and storage (CCS) even if CCS remains the best demonstrated technology within the 

EGU GHG NSPS. Two additional control options that should be discussed in the 

proposed rule are 1) co-firing with biomass or biofuels and 2) the purchase of verified 

GHG emissions offsets. Co-firing liquid, solid, or gasified biogenic-origin fuels should be 

discussed in this NSPS as a proven technology that can be selected by the EGU to 

achieve the NSPS emission limits. We have not determined CCS to be the “best 

demonstrated technology within the EGU GHG NSPS.” We will discuss co-firing with 

biomass/biofuels in the revised proposal (though the Agency is still formulating a policy 

for addressing emissions from biomass/biofuel use). 

o In the sections that discuss PSD and Title V programs, EPA should consider adding 

language that acknowledges the current analysis of biogenic CO2 emissions and 

applicability under PSD, Title V, and the Tailoring Rule. The RIA Executive Summary 

includes the statement, “The availability of the NSPS also will reduce uncertainty 

concerning Prevention of Significant Deterioration (PSD) Best Achievable Control 

Technology (BACT) determinations”. Without a clear ruling from EPA on biogenic CO2 

emissions from stationary sources [due in 2014] it will be difficult to rule out all PSD 

BACT uncertainty. Addressing biomass as explained above.

o Based on the latest eGRID data (2010 data for 2007 operating year), in 2007 there were 

213 power plants with greater than 25 MW capacity using some form of biomass to 

generate a portion of their electricity. These include some power plants with primary 

fuels (oil, coal, and gas) that would presumably be covered under the proposed NSPS if 

they were built as new facilities. The current proposed rule provides no guidance for 

how co-firing by these facilities would be treated. The rule does not cover existing 

plants; use of biomass by new facilities will be addressed as explained above

o As the proposed rule is currently written, there is uncertainty where EPA is drawing the 

line between fossil fuel facilities and biomass facilities. Many power plants with 

biomass as a primary fuel also rely on fossil fuel as a secondary fuel. Only 40 of the 213 

plants mentioned above generate all of their electricity from biomass. Furthermore, 

some of these biomass facilities likely have considerably lower intensity of CO2 

emissions per MWh (when adjusting for feedstock source) than NGCC power plants, 

which raises concerns about the reliance of NGCC as the basis for setting the level of the 

performance standard. Granted, it is not clear how the Accounting Framework for 

Biogenic CO2 Emissions from Stationary Sources, EPA’s Scientific Advisory Board (SAB) 

and the subsequent EPA PSD regulations will address biogenic CO2 emissions, but this 

process is underway and should be recognized within the EGU GHG NSPS. The EGU GHG 

NSPS will be affected by the final determinations of the “Biogenic CO2 SAB Process”. 

The interconnection of these two regulations that are simultaneously under 

development should be discussed in the RIA and the draft NSPS. See discussion of 

biomass above. The applicability is based on the ability to burn 250 MMBtu/h. As long 

as the fossil burners are greater than 250 MMBtu/h then the proposed standards apply 
Summary of Interagency Working Comments on Draft Language under 

EO12866/13563 Interagency Review. Subject to Further Policy Review.

18

regardless of how much they are actually used. Similarly, if a facility has 249 MMBtu/h 

fossil burners they can run continuously and the proposed standards would not be 

applicable. 

o The relative cost-effectiveness of CCS versus biogenic-origin fuel co-firing is likely to vary 

considerably by region of the country, reflecting both differences in the availability of 

biomass feedstocks such as agricultural and timber waste materials and the variety of 

sites for sequestering captured carbon from CCS systems. Since a portion of the 

transitional sources are planning to co-fire biogenic-origin fuels, this would seem like an 

additional justification to include co-firing in the proposed NSPS see discussion of 

biomass above

 The proposed rule does not address the use of waste heat in Combined-Heat Power 

applications. While the largest power plants are often larger than the typical US CHP 

application, CHP is possible on facilities likely to exceed the 25 MW threshold. Editing the 

denominator of the standard to “MWh or utilized heat equivalent” rather than simply MWh 

would allow such waste heat applications to be incorporated into performance standards for 

fossil fuel EGUs. The proposed standards provide a 75% credit for useful thermal output. 

Owners/operators would measure the useful thermal output, multiply the output by 75%, and 

then add that to the electrical output.

 Several interagency commenters suggest that EPA consolidate the preamble discussion of CHP 

to clarify how the rules apply, or don’t apply, to CHP facilities. We are editing the preamble to 

address these concerns.

Emissions Averaging 

 Page 61: “Because we expect CCS technology to advance over the next several years, we believe 

that it may not be necessary to include this type of alternative compliance option for a 30-year 

average the next time we review this NSPS.” Based on the scenario provided that some plants 

could wait to commence construction until after 2020 and still meet the 30-year average, it 

seems that consideration of terminating the alternative option in 2020 with flexibility only for 

those that have commenced construction prior to 2020 would create problems for those who 

planned construction after 2020, according to the above hypothetical. Will facilities that are 

already making plans under the 30-year average option be “grandfathered” such that they will 

not be forced to potentially accelerate their installation of controls based on a 2020 revised 

standard? - See response above

 While EPA has explained portions of the proposed rule at length in Section IV, there is no 

specific part within the proposed rule dedicated to EPA’s rationale behind its decision to allow 

30-year averaging as a method for compliance under CAA section 111(a)(1). While EPA has 

provided extensive comment in other sections about its use of 30-year averaging, it has not 

provided an explanation as to why it chose not to include other flexibility options that may be 

available in this context. – See response above

 On page 61 EPA notes that in the event that the EPA adopts the alternative compliance option, 

then at the time of the next required review, the EPA will evaluate the state of development or 

commercialization of CCS technologies and make a determination as to whether or not the 30-

year averaging approach is still warranted for new sources. Please clarify that any change in the 
Summary of Interagency Working Comments on Draft Language under 

EO12866/13563 Interagency Review. Subject to Further Policy Review.

19

consideration of the 30-year averaging option will not affect the units already permitted with 

this option. – See response above

 Why is 1 year averaging optimal? Has EPA considered taking comment on an optional longer 

averaging period? – As explained above, we believe that one year provides sufficient flexibility 

to address startup/shutdowns and variable fuel quality, while still allowing for timely 

demonstration of compliance.

Miscellaneous Comments 

 Page 177, Section M: We suggest that EPA define the timeframe over which the notable 

impacts of this rule on emissions and costs or energy supply decisions are considered to be 

negligible. – EPA specifically analyzed costs in 2020, but its analysis also showed that in most 

cases (including the reference case), there would be no new coal-fired generation and thus no 

costs through at least 2030. We will ensure that the RIA makes this clear.

 Purchasing verified offsets of GHG emissions, particularly offsets from agricultural and forest 

sources, is likely to be a more cost-effective form of GHG emissions reductions than CCS in the 

near to mid-term. EPA’s proposed rule should include discussion of offsets as an alternative to 

CCS and co-firing. The proposed rule provides an opportunity for EPA to begin to separate 

technical uncertainty regarding offsets (e.g.: how to address additionality and verification 

concerns) from legal uncertainty (e.g.: whether offsets are compatible with NSPS and other CAA 

regulations.). See response above

 How do the reporting requirements of this proposed NSPS compare to the reporting 

requirements of the GHG reporting rule? Monitoring requirements are generally consistent, but 

small modifications (e.g. ensuring that units report generation from Heat Recovery Steam 

Generators in all cases and that steam from cogenerators was provided) may be necessary.

 The current benefit-cost analysis projects that the NSPS will have no costs or benefits due to the 

fact that no new coal-fired power plants are projected to be constructed in the next decade 

even in the absence of the rule. This in turn is related to projections of future fuel prices, and 

particularly the relative prices of natural gas and coal. Given uncertainty regarding fuel price 

projections, we suggest that EPA include in the preamble and/or RIA a discussion of how far the 

relative prices of natural gas and coal would have to shift before EPA would project some new 

non-CCS coal plants in the reference case (i.e., in the absence of the rule). This would provide 

readers with a better picture of how likely it may be that the rule would impose costs and 

provide benefits. – EPA has added this to section V of the RIA, the price is approximately above 

$9.60 TCF.

 In addition, commenters suggested that this rulemaking could having a significant impact 

through its influence on the PSD permitting process, independent of the assumptions regarding 

the construction of new coal-fired power plants. Has EPA analyzed the potential influence of 

this rulemaking on future permits, since the NSPS would influence what is BACT by statutory 

construction? Although indirect, these potential costs and benefits would fall clearly within the 

type of impacts contemplated for analysis in an RIA. – EPA does not believe that this proposal 

would increase costs related to BACT analysis for new EGUs.

 The rule makes the case that no new coal-fired generation without CCS will likely be built absent 

the rule. What about less efficient natural gas units? - The less efficient gas that would likely be 

built would be simple cycle turbines (used 3,000 hours or less per year) which are not covered 

by this rule.
Summary of Interagency Working Comments on Draft Language under 

EO12866/13563 Interagency Review. Subject to Further Policy Review.

20

 Are all simple cycle combustion turbines exempt from these standards, regardless of whether 

they exceed the 3,000 hour threshold? If so, could this exemption create a perverse incentive to 

build less efficient combustion turbines in order to avoid compliance? The applicability is based 

on permitted allowable annual hours of operation for both simple and combined cycle turbines. 

Because this should not change the costs of building either type of unit, it should not create any 

perverse incentives.

 How do the proposed monitoring requirements compare to existing monitoring requirements 

for state CO2/GHG regulations? Can these requirements be harmonized for units that must 

comply with both state and federal CO2 regulations? - As noted above, the only changes to 

reporting requirements would be those needed to ensure that full credit was provided for all 

useful output (e.g. steam use, generation from HRSG).

 Can EPA please provide the interagency reviewers with additional explanation about the NSR 

pollution-control-project exemption mentioned on page 129? - The agency can provide any 

additional explanation if necessary.

 In a number of places throughout the preamble, EPA refers to “commenters.” Can EPA please 

clarify who these commenters are, given that this is a proposed rule? EPA held a series of 

listening sessions and allowed for additional comment after announcing it was moving forward 

with an NSPS for GHGs from EGUs. Commenters refer to those who commented during that 

process. We will make sure that is clear in the preamble.

RIA Comments

Chapter 4:

1) Page 1: Suggest an additional column showing average capacity factor be added to the chart. 

From a simple glance at the numbers to the uninformed, it appears that natural gas would 

generate the most electricity. A statement should also be added to impress that these are the 

physical capabilities of the equipment, and not the actual output. We have added the average 

capacity factor to Table 4-1 and note directing reader to Table 4-3 for net generation.

2) Page 3: Many gas units are used for “shoulder loads” and vary the output to match demand. 

The standard that is proposed shows that plants operating below 100% of the peak load will 

operate at lower efficiencies. Has an analysis been done to show that the average operation of 

a new combined cycle unit can meet the proposed GHG standards? I.E., if a plant is dispatched 

in such a way that the generation varies between 40% and 70%, it may not meet the proposed 

standard. Not all new gas-fired plants will operate as base-load units. EPA believes that the 

only less efficient gas would be simple cycle peaking turbines. Added language indicating these 

are not subject to rule.

3) Page 10: The description of CCS could benefit from plant system diagrams – perhaps sourced 

from the Task Force report. Added two diagrams from Task Force report illustrating postcombustion and pre-combustion CO2 capture.
Summary of Interagency Working Comments on Draft Language under 

EO12866/13563 Interagency Review. Subject to Further Policy Review.

21

4) Section 4.5 of the RIA highlights six methods for reducing CO2 emissions from the power sector: 

(1) carbon capture and storage; (2) improved fuel efficiency; (3) switching to lower-emitting 

fuels; (4) increased generation share from lower-emitting sources; (5) decreased loss of power 

via transmission and distribution systems; and (6) improved end-use efficiency lowering 

electricity demand for the same level of service provided. The RIA only discusses options (1) and 

(2) without addressing items (3), (4), (5), and (6). EPA should consider discussing these other 

options in the RIA as well as in the propose EGU GHG NSPS. Added sub-section to highlight 

remaining methods.

5) Section 4.6: The commenter suggests adding additional information on regulation from existing 

plants, even a statement that they will be proposed in the near future is warranted. Added note 

on future existing source standard.

6) Page 8: A reference for the report cited in the following sentence – “Coal emits around 1.7 times 

as much carbon per unit of energy when burned as does natural gas and 1.25 times as much as

oil (EIA 2004)” – does not appear be provided in section 4.9. Updated

7) Page 21: The internet link for this publication is not correct: U.S. Energy Information 

Administration (U.S. EIA). Electric Power Annual 2003. 2003. Available online at: 

http://www.eia.gov/oiaf/archive/aeo03/index.html. Rather it should be 

http://www.eia.gov/electricity/annual/archive/03482003.pdf. Updated

Chapter 5:

1) General: The analysis from EIA and EPA both show that with low gas prices, gas combined cycle 

plants will be the preferred alternative. It may be helpful to run a sensitivity case with higher 

natural gas prices. Higher gas prices would drive builds towards coal, which would provide a 

different possible aspect of the impact of this rule. Additional sensitivities have been performed 

demonstrating that under a wide range of circumstances, no new coal is built in the 2020 timeframe.

2) Page 2: Suggest stating that NEMS does not predict any CCS projects other than the ones built 

with DOE funding. – Have added this language

3) Pages 2- 3: The last paragraph on page 2 refers to the robustness of EIA’s projections of no new 

unplanned coal-fired capacity additions through 2020 across a number of different Annual 

Energy Outlook 2011 (AEO2011) sensitivity cases. Rather, the statement is made that the 

economics favor new builds of NGCC. In actuality, there really isn’t much in the way of 

unplanned NGCC projected to be built through 2020 in the AEO2011 sensitivity cases either. In 

addition, there are some significant builds of cumulative unplanned coal-fired capacity additions 

projected for the electricity sector in the AEO2011 low shale and no GHG concern cases in the 

post-2020 time frame, with 12.2 GW projected by 2035 in the Low Shale Estimated Ultimate 

Recovery (EUR) case and 8.3 GW by 2035 in the No GHG Concern case. – Have clarified.

4) Page 3: The end of the first paragraph states that “The economics favoring new NGCC builds 

instead of conventional coal are robust under a range of sensitivity cases examined in the AEO. 

Neither planned nor unplanned additions of coal by 2020 increase in sensitivity cases that 
Summary of Interagency Working Comments on Draft Language under 

EO12866/13563 Interagency Review. Subject to Further Policy Review.

22

examine higher economic growth, lower coal prices, low fossil costs, no concern regarding 

future GHG policy, slow oil and gas technology deployment, low shale gas recovery per play, and 

low shale gas recovery per well.” It should be noted that in the low shale gas recovery per play 

and low shale gas recovery per well cases, gas prices rise above $8/mmBTU shortly after 2020 

and some new coal plants are built. Therefore, it should be noted EIA runs do suggest that if 

shale gas production turns out on the low end of the spectrum, the economics do support some 

new coal. – Have done additional sensitivity work and caveated discussion of EIA analysis.

5) Page 9: Some of the numbers in Table 5.3 do not match what we have published on the AEO 

website http://38.96.246.204/oiaf/aeo/electricity_generation.html Have corrected.

6) Much of the 2010 data is now available in the 2010 Electric Power Annual. There are several 

figures and charts in the report that are citing 2009 data and could be updated. Have updated

General RIA Comments

 Given the difficulty of knowing whether any new coal facilities would, in the absence of the rule, 

be built, we suggest that EPA conduct sensitivity analyses looking at the potential costs/benefits 

of the rule in cases where limited new coal generation would have been constructed in the 

reference case. For example, EPA’s analysis suggests that new coal becomes economically 

viable at baseline if gas prices reach $8. There may be a low probability of this price occurring, 

but to the extent that it is possible, expected costs (and benefits) should be greater than zero. 

Also, EPA recognizes that new coal may be built even at projected prices for reasons beyond the 

scope of their modeling exercise (gas transmission issue, for example). These uncertainties 

suggest that some sensitivity analyses would be justified. Have performed additional sensitivity 

analysis.

 As mentioned above, EPA should also provide an analysis of the potential impact of this 

rulemaking on the PSD permitting process. Some commenters have stated that this rulemaking 

package appears to be significantly more aggressive than EPA’s current BACT guidance for GHG. 

If this rulemaking can be reliably predicted to increase the stringency of permitting decisions, 

then EPA should analyze that potential impact. – See discussion above, will note this in RIA.

 On slide 13 of the briefing given to the interagency team on 11/17, the results of an EPA staff 

analysis of the costs of several fossil based generation options was presented. Can you please 

provide the assumptions that went into this analysis? Additionally, could you compare these 

assumptions to those behind the CCS task force report cost estimates for a similar set of fossil 

based power generation options? In addition please include the PC+CCS option using the 

assumptions of the EPA staff analysis. 

The assumptions for the analysis shown on slide 13 of the briefing given to the interagency team 

on 11/17 are given in the table provided below.
Summary of Interagency Working Comments on Draft Language under 

EO12866/13563 Interagency Review. Subject to Further Policy Review.

23

New Coal 

w/o CCS

New NGCC New IGCC 

w/90%CCS

Capacity Factor 85% 85% 85%

MW net 600 560 500

Btu/kWh net 8,875 6,810 10,150

Fuel Bituminous 

$2/MMBtu

Natural Gas Bituminous 

$2/MMBtu

$/kW net 

(2007$)

2,920 +IDC 980 +IDC 4,720 +IDC

Capital Recovery 

Factor

11.1% 12.1% 11.1%

COE $/MWh net 77 75 122

IDC = interest during construction

Regarding the request to show COE and assumptions for new PC w/CCS, given the current 

uncertainties in cost/performance, EPA engineering staff regard new IGCC w/CCS and new PC 

w/CCS to be economically equivalent in terms of COE.

Regarding the request to compare EPA's COE values and assumptions to those used in the 

Interagency CCS Task Force Report – NETL developed the COE values shown on pg 31 of the 

report (http://www.fe.doe.gov/programs/sequestration/ccstf/CCSTaskForceReport2010.pdf); 

detailed assumptions were not provided.

 Much of the 2010 data is now available in the 2010 Electric Power Annual. There are several 

figures and charts in the report that are citing 2009 data and could be updated. Updated 

where new data available.

 Could you please provide an estimated cost for each of the following generation configurations 

in both compliance options (currently meeting the 1000lbs/MWh limit v. meeting the 30 year 

averaging limit).

o New USC PC Plant –see below re IGCC plant

o New IGCC Plant – In its cost modeling, EPA does not consider a number of key factors 

that would need to analyze this request. EPA models a generic advanced coal unit with 

90% capture. To comply with a standard currently meeting 1000 lbs/MWh, sources in 

fact could construct units with closer to 50% to 60% capture. Analysis by others have 

suggested that requiring less reductions could significantly reduce costs. We have 

augmented the preamble to indicate that according to analysis performed by the Clean 

Air Task Force, this could cost approximately $116/Kw, while reductions of about 90% 

could cost approximately $147/Kw, however, with technology improvements expected 

to occur based on the large scale projects being pursued, that number could be lower by 

the time that a company using the 30 year averaging limit would have to implement 

CCS.

o New NGCC Plant – There is no incremental cost associated with this option, as NGCCs 

meet the limit
Summary of Interagency Working Comments on Draft Language under 

EO12866/13563 Interagency Review. Subject to Further Policy Review.

24

o Existing PC with a major modification – modifications are not covered by the proposed 

rule.