## 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 implemen ted. ” Several commenters note that c apture, compression, transport ation and storage at full scale on coal

fired power applicatio ns 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 Vatte n fall

-Alstom oxyfuel/CCS project at Schwarze Pump e in Germany, Southern Company is currently building a full scale utility CCS project in Mississippi. Addition ally, 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 p rices 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 av ailability 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 r educe 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 impleme ntation 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 fairl y 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 natur e of CO 2 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 CO 2 pollution from fossil

- fuel

fired power plants because they are responsible for 40 perce nt 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).

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exists that can be readily and cost

- effectively used to reduce GHG emissions from these s ources. 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 emis sions 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.

 I n 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 iden tified 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, t his 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 o f emission reduction that is adequately demonstrated for this category of sources. The standard could also be met by coal plants with CCS. While E PA does not predicate this proposal on CCS technologies being commercially available for all applications wi thin 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 t he 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 reduct ion 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 red uction for

## Summary of Interagency Working Comments on Draft Language under

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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 pleas e 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 proje cts. 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 co mplete financing information on all of the projects cited, we a gree 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 Supercri tical 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 n ationwide 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 ap plicable 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 CO 2 can be (and currently is) transported over lo ng distances via pipeline ,
2 “Your View: The Dirty Truth a bout the Taylorville Energy Center”, Crain’s Chicago Business News, November 25, 2011.

## Summary of Interagency Working Comments on Draft Language under

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4 projects using EOR can be located throughout the country. Currently projects providing CO 2 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 CO 2 for enhanced oil recovery in Saskatchewan, Canada

. EPA believes that interagency commenters may be envisioning a much more significant use of CCS than is contemplat ed by this proposed rule. It fo cuses on new and reconstructed power p lants and does not focus on the existing coal plants that provide the vast majority of the coal

fired generation

. The EPA agrees that there are differences in the characteristics of the coal and pet coke fuels used in an IGCC process. T he EPA also understands that the syngas es 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. L essons learned from development of tho se 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 com menters 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 w ithin 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 no te, the thirty year average is an alternative compliance mechanism that EPA is proposing companies may use. It is not requiring the use of it. S ome 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 use d to reduce GHG emissions from these sources”.
– As noted earlier, this second st atement 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 technologi es 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
. There fore, 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 t he social cost of carbon.

o Commenters also suggested t his 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

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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 set s 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? T he 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 CO 2 in large amounts, including fossil fuel

- fired power plants .... “. Finally, th e cited language was written to address the BA CT 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 th e 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, th is 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 stat es, “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 wi ll 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 complianc e option EPA adopts under NSPS will have effects on BACT; therefore, it’s important that EPA’s conclusions are consistent and well

supported. 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

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6  Page 19: It is stated: “The proposed rule w ill 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 state ment 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 conditio ns 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

. T herefore, 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 a lthough 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 d emand 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? S ee attached analy sis where we have examined a high er electricity demand sce nario designed to simulate improved economic conditions.

 Also on page 89, EPA notes that n atural gas prices have stabilized over the past few years as new drilling techniques have brought additiona l 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 high er gas price s cenario
.
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 cert ain 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 b ecome 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/

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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, b oth 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 fac ility (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, 1 st Paragraph: This pa ragraph lists the CAA Section 111 requirements pertaining to the establishment of a standard of performance for CO 2 emissions from EGUs. Cost and adequate demonstration are two important considerations mentioned for the best system of emission reduction s elected. Several commenters have suggested that i t appears that these two considerations have not been adequately addressed in the preamble for the CCS technology selected as the best system of CO 2 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 emission s reduction.

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

-fired powe r 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 CO 2 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 CO 2 emission changes (see Page 155) from this r ule, 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 re vised to present a more relevant rationale. EPA believes there are multiple policy rationales for this rule. T he power sector is the largest single stationary source category of CO 2 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 abr oad.

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

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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 m issing from the performance adjustments cited by EPA : EPA has performed an additional analys i s 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 compl ete generation data to the Agency. Based on th is 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 elevation s and ambient te mperature s ), 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 availa ble 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 period s of natural gas with high er 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, no t 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 pot ential 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 turbin e), 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% perform ance 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

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of the renewables and thus b e 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 varie ty 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 s tandby 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 CO 2 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 in crease 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 opt ions. 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 inste ad of us ing 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 201 1 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.

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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 shu tdown 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 facilit ies. 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 rul e, 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 inc luding 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 assumpt ion 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 bein g 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 foreseeab le 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 lim it 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

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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 databas e 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 th is topic, we are editing the preamble and the p roposed 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 explanatio n 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 alterna tive 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 sup ercritical 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 revi ew. 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 sma ller 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 emissio ns 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 supercriti cal and ultra

- supercritical designs. These pl ants 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 exi sting 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, whic h 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

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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 ha s maintained a 12

- month emissions rate of 1,730 lb CO 2/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 unti l 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 constructi on 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 202 0 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 assum e 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, cost

effective 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 legall y 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 approxim ate 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 So urces** 

 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,

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13 transitional sources that do not commence construction within 12 mon ths 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 reques t 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), t his 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 gen erally 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 thes e 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 w ith 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 l imits , 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, a re 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 tr ansitional 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 u nder 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 modificati ons 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 sour ce” 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 ex empt 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

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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. Th e 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 w ith 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 gre ater 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 p ollution 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? D oes 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 i ncrease hourly CO 2 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 t hat 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 regula ted 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 ca tegorization 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 uncertain ty 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 finaliz e 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.

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15  Page 160, 2nd Paragraph: Thi s 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 th e 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% e fficiency, 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 t he 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) t o 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 withi n 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 a ccount 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 re tained 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 conven tional emissions from natural gas

-fired EGUs.” 4 Yet, 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 oppose d to 1,100 lbs CO2/MWh for NGCC. 5 While coal

fired boilers with CCS can achieve similar levels of GHG emissions as combined cycle gas boilers , they can no t 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 a chieved 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.

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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 syste m 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 uni ts. 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 pet

coke

-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 a n 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 reduct ions.  Several commenters note that w hile 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 flexi bility options that may be available in in the context of the “best system of emission reducti on” 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 issu e in the draft rule.
– See response above
 One commenter requests that EPA expand o n 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.
– P eaking turbines only account for small amounts of GHGs ; th is rule focuses on more frequently operated and higher emitting plants.
 Page 27, 1st Paragraph: It is stated: “These increase s 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 ad d

- 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 mas s 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 Ene rgy 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.

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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 tha t t he 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 high er domestic electricity prices. A s 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 N SPS. 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 discus sed 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 t he 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 b iogenic 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. T he rule does not cover existing pla nts ; 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 emissi ons 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 C O2 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 applic ability 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

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regardless of how much they are actually used. Similarly, if a facility has 249 MMBtu/h fossil burners they c an 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 li ke 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 th e 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 incorporat ed 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 accelera te 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 inc lude other flexibility options that may be available in this context.
– See response above
 On page 61 EPA notes that i n 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

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19 consideration of the 30

-year averaging opt ion 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, w e believe that one year provides suffi cient flexibility to address startup/shutdowns and variable fuel quality, while still allowing for timely demonstration of compliance. **M iscellaneous 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 gener ation 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 emissio ns 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 r eporting requirements of the GHG reporting rule? Monitoring requirements are generally consistent, but small modifications (e.g. ensuring that units report generation from Heat Re c overy 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 r elative 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 ru le 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 constru ction? 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.

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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 an d combined cycle turbine s . 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 reg ulations?

- 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 additi onal 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 duri ng 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 th at 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 stand ard. 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 bene fit from plant system diagrams
– perhaps sourced from the Task Force report. Added two diagrams from Task Force report illustrating post

combustion and pre

- combustion CO 2 capture.

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21 4) Section 4.5 of the RIA highlights six methods for reducing CO2 emissions f rom 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; an d (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 RI A 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 fut ure 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.ei a.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 s how 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 poss ible 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 time

frame. 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 Annua l 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 c ases 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 rob ust 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 pol icy, 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 sh ortly 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 a nd 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_genera tion.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 constru cted 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 (a nd 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 sensi tivity 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 ru lemaking 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 d iscussion 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 a ssumptions 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 dur ing 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. Regardi ng the request to compare EPA's COE values and assumptions to those used in the Int eragency 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 rep ort 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. m eeting 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 augm ented 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.