From: Frey, Nathan J. To: Wayland, Robertj ; Culligan, Kevin Cc: Higgins, Cortney ; Laity, Jim Subject: Summary of Interagency Comments Under EO 12866 & 13563 -- EGU NSPS NPRM 2060-AQ91 Date: Friday, August 02, 2013 8:46:28 PM Attachments: Summary of Interagency Comments under EO_12866_13563 EGU_GHG_NSPS_2060-AQ91_NPRM.docx Summary of Interagency Comments Under EO 12866 13563 EGU NSPS_2060_AQ91.docx 

### Attached please find a summary of interagency comments under EOs 12866 and 13563 regarding the EPA proposed rule, Standards of Performance for Greenhouse Gas Emissions from New Stationary Sources: Electric Utility Generating Units. Thanks and please let us know if you have any questions.

Nathan

## Summary of Interagency Working Com ments on Draft Language under EO12866 Interagency Review.  Sub ject to Further Policy Review.

1 Summary of Interagency Comments on U.S. Environmental Protection Agency’s Notice of Proposed Rulemaking “Standards of Performance for Greenhouse Gas Emissions from New Stationary Sources: Electric Utility Generating Units” (RIN 2060

‐ AQ91)

General comments:

 EPA plans to prepare a separate Federal Register notice rescinding the April 13, 2012 proposal. The commenter would appreciate the opportunity to review that notice.

 Has EPA considered whether there is any ongoing benefit or significance to the rationale that was put forth in the April 2012 proposal, and whether the April 2012 justification is complementary to the rationale set forth in this proposal?

 EPA demonstrates that no reasonable forecast predicts a cost advantage to building an electricity generating unit (EGU) that would not be compliant with the proposed standard. Given that, what is the rationale for promulgating the rule? EO 12866 states that “federal agencies should promulgate only such regulations as are required by law, are necessary to interpret the law, or are made necessary by compelling public need, such as material failures of private markets.” Can EPA clarify whether this rule is required by law or necessary to interpret the law?

EPA notes that the rule would provide regulatory certainty and thereby incentivize innovation. It is unclear how a regulation that would not require any change in behavior would incentivize companies to invest in technologies to further reduce emissions, unless there were external market forces that would prompt them to do so. In which case, the regulation would not be needed. Can EPA explain this line of thinking further?

 What is the legal justification for providing an exemption to Wolverine should it not have commenced construction by publication?

 According to some technical experts, we understand that it may be possible to design and construct a hybrid EGU that combusts both coal and gas. How would such a plant be treated for purposes of NSPS compliance?

Best System of Emission Reduction (BSER):

 The commenter requests clarification on whether EPA’s definition of BSER enables other technologies that meet the same level of emissions reduction (e.g., chemical looping and oxy ‐ combustion).

 For the proposition that CAA section 111 standards may impose a greater compliance burden on some sources in a category (page 179

‐ 185), EPA may also wish to cite the recent case of Portland Cement Ass’n v. EPA , 665 F.3d 177 (D.C. Cir. 2011). In Portland Cement , the court upheld EPA’s approach that focused “primarily” on cement kilns with a newer design incorporating a state

‐ of

‐ the

‐ art technology, rather than older

‐ designed kilns that would become subject to the NSPS if modified. EPA found that the older

‐ designed kilns had available controls that could enable them to meet the standard, but noted that it would be “more difficult” for

## Summary of Interagency Working Com ments on Draft Language under EO12866 Interagency Review.  Sub ject to Further Policy Review.

2 them and would entail somewhat higher cost; thus, EPA considered separate standards for the older kilns but ultimately decided against that approach.

 Although not stated explicitly, the justification for reasonable cost seems to imply that the net compliance costs must be negative, that the revenue from EOR must fully offset the increased cost of partial CCS. If this is the correct interpretation, it could potentially set a restrictive precedent that carbon pollution standards only have reasonable cost if they are expected to be cost

‐ saving irrespective of environmental benefits. Again, while the rule doesn’t state this explicitly, we note that in table 4 the levelized cost of electricity under the standard with high EOR is equal to or less than cost without CCS for both SCPC and IGCC. EPA may wish to clarify whether costs could still be considered “reasonable” under this analytical framework if EOR revenue estimates did not lower net costs to the level of an uncontrolled plant. Additionally, while EPA considers the revenue from EOR to lower overall costs, the preamble doesn’t appear to consider additional CO2 emissions from recovered fossil fuels to be an environmental disbenefit. Should the recovery and combustion of fossil fuel from EOR that would otherwise remain underground be considered in the economic analysis?

 EPA states that it is logical and a reasonable interpretation of the statute that the costs of the control technology should be offset by any revenues from the sale of pollutants or pollution control byproducts associated with those controls. Has EPA applied this logic in any other NSPS (or other similar and relevant context)? See page 160. It would be helpful to further elaborate on this issue in the preamble.

Level of standard:

 The commenter suggests that the range on which comments are solicited for the proposed emission limit for new fossil fuel

‐ fired boilers and IGCC units be amended from 1,000

– 1,200 lb CO2 / MWh to [900]

– 1,200 lb CO2 / MWh. The lower bound of this range, which we tentatively suggest to be [900], would be at a level slightly above the feasible level exemplified by the Great Plains Synfuels Plant and the Kemper County Energy Facility—which appears to be approximately 900 lb CO2 / MWh. The economic analysis in the rule and the RIA did not provide strong reason to think that such plants would be unduly expensive in the future, and the fact that these are being built in fact suggests that they are not unduly expensive currently and thus could be consistent with BSER.

 Can EPA provide additional explanation and justification for why it is appropriate to set the BSER level at 45% capture, as opposed to a higher or lower level of partial capture? It would be helpful to have more detail on why the chosen level (as opposed to other levels) was selected, and the basis for that determination. For example, can more detail be provided on the thresholds or tipping points for capture above which costs jump significantly? Or is there greater evidence of the achievability of this level of capture based on real

‐ word experience? If so, further explanation could help strengthen the BSER determination section of the preamble. (We note that EPA has provided some detail on the technical reasons for the choice (e.g. it is cheaper to use a single “water gas shift” cycle in part because the resulting syngas does not require a specialized H2 turbine that would be required if multiple water gas shifts are used,

## Summary of Interagency Working Com ments on Draft Language under EO12866 Interagency Review.  Sub ject to Further Policy Review.

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

 In section VII.L “Compliance Period” EPA proposes a 60 operating

‐ month compliance period for new fossil fuel

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

‐ year compliance period. What data and analysis method is EPA using to interpolate between the April 2012 proposal (1,000 lb CO2 MWh with full CCS” and 30

‐ year compliance period) and the regulations currently applicable to these sources, in order to arrive at the proposal under consideration (950

‐ 1,050 lb CO2 MWh with “partial CCS” and 60

‐ operating

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

‐ operating

‐ month compliance period.

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

 Page 327

‐ 328. The discussion of parasitic loads and gross ‐ versus net

‐ based standards could be improved by tabulating the relevant SCPC and IGCC coal plants, with and without CCS, thereby demonstrating the parallel gross and net standards and how these were calculated and inter

‐ relate. Otherwise, the text as currently written states that 1400 lbCO 2 /MWh would be the net basis for a coal

‐ CCS plant, which differs little from the (gross) coal without CCS performance numbers noted for high performing units of 1434 lbCO 2 /MWh (p. 188; p. 200), at least at first blush without the benefit of the parallel display of figures. Below is a sample table cobbled together from numbers reported in the FR

– the square parentheses represent imputed numbers rather than stated in the text. Gross Emissions

(lbCO 2 /MWh) Parasitic Load Net Emissions (lbCO 2 /MWh) SCPC 1675 ‐ 1783 <7.5% [1800 ‐ 1916] IGCC 1434 15% [1649] Coal

‐ CCS 1100 [27%] 1400 NGCC (<=850 MMBtu) 1100 2.5% 1130

NGCC (>850 MMBtu) 1000 2.5% 1030

Simple Cycle/Peaking plants:

 The rule clearly states that the intended facilities to be covered are intermediate and baseload generation and exempts “peaking” plants. While the rule provides a reasonable justification for treating these sources differently than intermediate or baseload generation, why were these sources exempted rather than setting a less stringent numerical standard for this subcategory? Given that availability of peaking plants is an enabling technology for renewable electricity, we could imagine that uncontrolled simple cycle plants could lead to higher overall power sector carbon emissions. Did EPA analyze this scenario as it relates to interactions with renewable energy growth?

 The commenter agrees with EPA’s determination that simple cycle units should not be subject to the same standards as combined cycle units. However, rather than entirely exempting simple

## Summary of Interagency Working Com ments on Draft Language under EO12866 Interagency Review.  Sub ject to Further Policy Review.

4 cycle units, EPA could formulate an alternative standard in recognition of the role simple cycle units play in complementing renewable sources and maintaining grid reliability. Are there plans to propose a standard that would apply to simple cycle units? If so it might be appropriate to mention such plans. This could be quite significant because of the increasingly important role expected to be played by simple cycle natural gas turbines as wind and solar power generation expands.

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

‐ year average capacity factor of greater than 33 percent between 2000 and 2012. Therefore, as noted, from a practical standpoint, few new simple cycle turbines be subjected to the standards of performance in this rulemaking.” It would be good to see the distribution curves here, because this still could impact some simple cycle turbines, raising the question of flexibility in implementation. With a projected increase in reliance on cyclical solar and wind power, presumably the amount of load following turbine cycling might be expected to increase. Maybe EPA has a graph that could be circulated as a memo?

 Page 144. EPA states: “Only 0.4 percent of existing simple cycle turbines had an annual capacity factor of greater than 40 percent between 2000 and 2012.” On the previous page EPA commented on only 0.2 percent over 3 years at 33%. Presumably the percent calculation differences relate to the time and rate input parameters, but it is a little confusing. Hence, a graph and memo would be helpful.

 Page 145. EPA states: “For example, a 33 percent efficient 100 MW facility would have a potential electric output of 876,000 MWh and a 40 percent efficient 100 MW facility would have a potential electric output of only 723,000 MWh.” I don’t understand the math here, whereas it was clear in the previous conversion of 25MW to a 219000 MWh annual equivalent. This calculation would seem to be 0.33 x 100 MW x 24 hr x 365 = 289080 MWh, but it is not. It also seems unusual that the less efficient plant has a higher potential electric output. Recommend a brief explanation of how the numbers are calculated, perhaps in a footnote.

 EPA should explain why smaller NGCC units meet a particular need. Is it geographic specific? Is there a possibility that multiple new smaller units would be built instead of one larger unit?

Technical feasibility of CCS for coal

‐ fired units:

 The draft NSPS regulation is “technology forcing” for carbon capture and storage (CCS) in that it establishes partial CO2 capture using CCS as the Best System of Emission Reduction (BSER) for new fossil

‐ fuel boilers and integrated gasified combined cycle (IGCC) units. The commenter agrees that carbon capture is technically feasible, but it has not been deployed at scale in commercial power plants. The commenter also agrees that Enhanced Oil Recovery (EOR) sequestration has been employed commercially. Nevertheless, demonstration projects will be necessary in a number of operating environments in order to reach the technical potential and the cost targets contemplated in the rule, and to demonstrate storage in saline aquifers. The commenter therefore believes the rule should incorporate sufficient flexibility to enable additional demonstration projects. This will ensure that the draft NSPS regulation is “technology forcing” for both carbon capture technologies and sequestration, whether EOR or geologic.

## Summary of Interagency Working Com ments on Draft Language under EO12866 Interagency Review.  Sub ject to Further Policy Review.

5  EPA’s assertion of the technical feasibility of carbon capture relies heavily on literature reviews, pilot projects, and commercial facilities yet to operate. We believe this cannot form the basis of a finding that CCS on commercial

‐ scale power plants is ‘adequately demonstrated.” o EPA should provide details of the specific CCS operations already in service that process the rate of CO2 necessary for a typical IGCC power plant to be in compliance. Where only literature reviews or simulations exist, the text should make this clear. o We are concerned that the unsupported assertions of technology as ‘adequately demonstrated’ in this rulemaking will form a precedent for future such determinations, even if the three CCS projects used as the basis for the determination fail or are never completed.

 EPA states that the level of the NSPS standard “best promotes further enhancement of the performance of existing technology and promotes continued development of new, better performing technology” (See page 199). Could EPA further explain why it believes that a standard level that can be met by existing technologies would spur development of new, better performing technology? Presumably, this is because we would expect a higher volume of CCS deployment at this cheaper capture level, thereby helping to develop the production experience needed to lower costs for related technologies that could ultimately be used to achieve higher capture rates. Further explanation on this topic would be helpful.

 Why is the Boundary Dam project not included in the listing of CCS demonstration projects (starting on page 212)? It is mentioned in two other places in the FR, as well as getting a prime place in EPA’s introductory powerpoint.

Costs of CCS:

 Can EPA please provide a brief explanation (on page 29) of why the cost of partial 65% capture are so much less than full 90% capture? This is made more evident in RIA Table 5

‐ 7, p.5

‐ 19, where the capital increment for partial

‐ 65% CCS is estimated at $305/kW, with a further $812/kW capital to get to full

‐ 90% CCS. Presumably this relates to additional technologies being added to a coal fired plant to go from partial to full capture, but the differential is quite high since much of the capital expenditure would presumably have gone into the IGCC and basic capture components. A technical explanation would be helpful.

 Page 219, Table 4. The NGCC @ $5.0/MMBtu estimate is actually substantially below the EIA 2013 estimate, in $2011, even if we extract the transmission costs. EIA reported $65.6

– $1.2 transmission = $64.4, compared to NETL/EPA $52. Is this difference fully explained by the range of modeled gas cost input prices, and, if so, might this calculation/explanation warrant a footnote?

 Attached are CCS costs prepared by DOE’s National Energy Technology Laboratory (NETL) based on two NETL studies, as well as current project cost data. These numbers provide a range of cost estimates for next

‐ of

‐ a ‐ kind plants. The commenter believes that it would be appropriate for the proposed rule to consider the full range of cost estimates developed by NETL, recognizing the level of uncertainty in these estimates.

## Summary of Interagency Working Com ments on Draft Language under EO12866 Interagency Review.  Sub ject to Further Policy Review.

6 The commenter notes that DOE is sponsoring research on novel carbon capture technologies and alternative coal conversion technologies that may substantially lower future CCS costs.

 EPA states that “regulatory programs may serve to defray the costs of CCS, including, for example, Clean Energy Standards or guaranteed electricity purchase price agreements.” This is the only discussion of these policies. EPA should discuss this further, instead of just mentioning them. (See page 230)

 Regarding transportation of CO2, it is not clear that the preamble addresses the costs that may be associated with any new pipelines that could be used for transportation, and specifically the cost to get CO2 from a facility to a GS site. It would be helpful for EPA to include a more detailed discussion on transportation (page 205).

 EPA should clarify the assumptions and estimates of costs associated with transportation of fuel, electricity and/or CO2 in its assessment of “reasonable costs.” See also related comments below regarding the RIA and NETL’s consideration of transportation costs. o EPA’s analysis assumes the cost of CO2 transportation is not “a significant impediment” to CCS, based on a history of CO2 pipelines and the distribution of existing CO2 sources. Instead, EPA should acknowledge that other factors can vary significantly the cost of CO2 transport. availability (or unavailability) of rights

‐ of

‐ way for new pipelines; capital costs; and operating costs (in terms of dollars, energy, and GHG emissions). o EPA discusses siting considerations as if they are costless (pp. 242). Additional siting considerations increase the cost of construction by requiring trade

‐ offs in that may not have existed in the absence of the regulatory mandate. These costs include transportation of coal and delivery of electricity from a location that would otherwise not be selected. As with CO2 transportation, these costs include availability (or unavailability) of rights

‐ of

‐ way for new pipelines or rail lines; capital costs; and operating costs (in terms of dollars, energy, and GHG emissions). Again, see RIA comments noting NETL’s acknowledgment of variability in such costs. o EPA asserts that gas can serve as a substitute when appropriate siting for a coal

‐ fired power plant is unavailable (pp 241). This implies the assumption that national electric markets are entirely integrated and electricity is a commodity with no regional variations. Further, though EPA assumes the baseline and regulated scenarios are equivalent, it is possible that resource and technology development paths between these two differ, thus weakening the strength of this assumption. We suggest EPA add language to further acknowledge the substantial uncertainty related to this assumption. Geologic Sequestration:

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

 Please note existing questions to EPA regarding the hazardous waste exemption rule for Class VI wells, and whether this should and could be extended in a separate rulemaking to UIC Class II wells that have monitoring, reporting, and verification (MRV) procedures consistent with GHG Reporting Rule Subpart RR. The FR text on page 255, refers to the use of both UIC Class II and

## Summary of Interagency Working Com ments on Draft Language under EO12866 Interagency Review.  Sub ject to Further Policy Review.

7 Class VI wells under GHG Reporting Rule SubPart RR as verification of sequestration for the purposes of the NSPS.

 EPA’s BSER determination for coal

‐ fired plants would benefit from a more clear explanation of the factual basis for determining that the long

‐ term storage of CO2 has been demonstrated. The preamble discussion should be strengthened on this topic. o Specific comment on p. 205: Can EPA provide a more direct explanation of how the permanence of storage has been demonstrated? The preamble talks about how storage locations and opportunities are available for geologic sequestration and EOR, but it does not discuss evidence that CO2 can actually be technically stored for long periods of time. It is our understanding that such evidence exists, and it should be explained. o Specific comment on p. 212: EPA notes that alternatives to geologic sequestration would need to address the

– “ultimate fate of the captured CO2 and the degree to which the method permanently isolates the CO2 from the atmosphere”

– but EPA does not describe in the preamble how its proposal meets addresses these points. EPA should explain its rationale and provide the supporting evidence. See also page 208 and page 260.

 EPA’s proposal will have significant disparate geographic impacts. Geologic features appropriate for EOR or geologic sequestration are not evenly distributed throughout the country. (See also related comments regarding RIA and NETL assumptions below). EPA asserts that such disparate impacts are permitted by the Clean Air Act, citing some legislative history (see e.g., pp 180

‐ 181). However, these quotations apply to the impact of the NAAQS provisions (i.e., local sources effect on local pollution), and the possible restrictions on construction of new sources in non ‐ attainment areas. The NSPS is a uniform emission standard for the whole country, imposed regardless of local levels of pollution. It is more inappropriate to exercise this discretion in this case, where local pollution does not have local effects. o We believe EPA confuses the legislative history regarding the distinction between a geographic restriction on new sources due to NAAQS and due to NSPS. EPA similarly has not distinguished between s siting considerations due to the regulated entity’s selected technology and due to EPA’s mandate of an “adequately demonstrated” technology that cannot be used in particular places (pp. 242). o EPA reminds us that the DC Circuit has said that sec. 111 standards “must not give a competitive advantage to one State over another in attracting industry.” Please explain how this instruction is consistent with a sec. 111 standard that is unattainable in parts of the country. o We would like to know of any other NSPS for which the “adequately demonstrated” technology was inappropriate for particular parts of the country, without respect for NAAQS or PSD.

 How will EPA enforce the requirement that captured CO2 be reported under the GHG reporting program? Is that requirement an explicit part of the “standard of performance” and therefore enforceable like any other part of the standard? (see page 255). We note that EPA is relying on MRV plans that are required under Subpart RRR of the GHG Reporting program to detect and quantify leakage (see page 252). What is not clear is what happens under Subpart RRR if leakage occurs. EPA should discuss this aspect of the overall approach.

## Summary of Interagency Working Com ments on Draft Language under EO12866 Interagency Review.  Sub ject to Further Policy Review.

8  If a covered entity meets the standard by capturing CO2 and sending it to a facility covered by the GHG reporting program but the geologic storage facility shows high leakage rates, would EPA have any ability to remedy the leakage problem or pursue enforcement action against anyone? It would be helpful to describe the agency’s thinking on this point.

CCS for Natural Gas:

 EPA states that NGCC is not “technically feasible” (on page 33, 264, and others), yet on page 265 notes that there is a demonstration project, which implies that CCS is technically feasible for NGCC. EPA does helpfully note that CO2 concentrations are lower in effluent from NGCC relative to coal

‐ fired power plants. Are there are other technical constraints to actually using CCS in the NGCC context? Or, are there financial and efficiency drivers involved that limit the use of CCS in the NGCC industry that should be further explained?

 Presumably, EPA has decided to set a GHG standard for new natural gas ‐ fired facilities that does not require additional emissions control technology because it is relatively cheaper to achieve the same level of emissions reductions from existing fossil fuel

‐ fired power plants (via a subsequent rulemaking). However, EPA does not appear to have provided any estimates on what it would actually cost new natural gas ‐ fired facilities to install and operate CCS technology. Isn’t data and analysis on the cost of applying CCS to natural gas ‐ fired facilities necessary in order to justify the decision that CCS is not BSER for new natural gas ‐ fired facilities?

 Because the rule considers CCS for natural gas infeasible there is no cost analysis of this option. The preamble provides evidence for why there is greater uncertainty in applying CCS for natural gas than coal; however, EPA may wish to request comment and attempt a cost analysis for the final rule. If nothing else, this may signal to the industry that CCS could be considered for natural gas during the statutorily

‐ required 8

‐ yr review.

The preamble asserts that CCS technology is increasingly difficult for natural gas plants that cycle to provide intermittent load, however, would it be possible to create a subcategory for baseload NGCC generation that would be more likely to meet BSER criteria? If that is the case, EPA may consider requesting comment on further subcategorization.

 Although technology that would make CCS for natural gas an efficient way to reduce emissions is not currently available, it would be desirable for EPA to signal that were technology to be demonstrated and to meet BSER criteria, then EPA would accordingly reexamine whether NGCC/CCS would meet BSER criteria in its next NSPS review cycle. Sending such a signal should serve to support R&D in natural gas CCS. One way for EPA to send this signal would be by including a cost analysis and a request for comment on CSS for natural gas in the final rule, although there might be better ways to send this signal.

 The briefing materials and draft NSPS Federal Register notice state that EPA does not have sufficient information to determine if CCS for natural gas is technically feasible. Recognizing that we are parsing the text closely here given legal requirements, we believe that more care needs to be taken in the selection of words and phrasing. To be clear, we agree that NG

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

## Summary of Interagency Working Com ments on Draft Language under EO12866 Interagency Review.  Sub ject to Further Policy Review.

9 determine if NG

‐ CCS costs are reasonable, and there are differences in system design and CO 2 concentrations, etc., between coal and gas power plants. That said, in discussions with industry and academics we have been informed that all aspects necessary for NG

‐ CCS have been demonstrated, albeit not configured, funded, or implemented. Concerns about the need for hydrogen turbines in certain configurations are not dissimilar from the considerations relating to coal syngas. In support, we note the BP

‐ SSE Peterhead precombustion NG

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

‐ SSE Peterhead Post

‐ Combustion NG

‐ CCS finalist proposal in the British CCS competition; and recent news reports from GE

‐ Sargas and Summit

‐ Linde that they are independently proceeding with NG

‐ CCS design and funding proposals. o http://ieahia.org/pdfs/PeterheadCase_Study1_2.pdf

o https://www.gov.uk/government/news/preferred

‐ bidders

‐ announced

‐ in

‐ uk

‐ s ‐ 1bn

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

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

‐ Sargas

‐ Announce

‐ Alliance

‐ Enhanced

‐ Oil

‐ Recovery o http://bellona.org/ccs/ccs

‐ news ‐ events/news/article/summit

‐ power ‐ and

‐ linde

‐ join

‐ forces

‐ to

‐ develop

‐ ccs ‐ for

‐ gas ‐ fired

‐ power ‐ generation.html

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

‐ CCS. We suggest the following edits: o Page 32: “By contrast, NGCC with CCS is not a configuration that is widely being planned and built today. The EPA considered whether NGCC with CCS could be identified as the best system of emission reductions adequately demonstrated for new stationary combustion turbines, and we decided that it could not be identified for several reasons. At this time, CCS has not been implemented for NGCC units, and we believe there is insufficient information to make a determination regarding the technical feasibility of implementing CCS at these types of units. The EPA is aware of only one NGCC unit that has implemented CCS on a very small portion of its exhaust stream. The EPA is not aware of any demonstrations of NGCC units implementing CCS technology that would justify setting a national standard. Further, the EPA does not have sufficient information on the prospects of transferring the coal

‐ based experience with CCS to NGCC units. In fact, CCS technology has primarily been applied to gas streams that have a relatively high to very high concentration of CO2 (such as that from a coal combustion or coal gasification unit). The concentration of CO2 in the flue gas stream of a coal combustion unit is normally about four times higher than the concentration of CO2 in a natural gas ‐ fired unit. Natural gas ‐ fired stationary combustion turbines also operate differently from coal

‐ fired boilers and IGCC units of similar size. The NGCC units are more easily cycled (i.e., ramped up and down as power demands increase and decrease). This cyclical operation, combined with the already low concentration of CO2 in the flue gas stream, lead to uncertainty about how technically feasible CCS technology might be demonstrated is for NGCC units absent further information. [note: GE

‐ Sargas propose using an aeroderivative turbine with multiple shafts to maintain gas pressures (to aid in capture) at varying turbine rates.] o Page 264: “We do not consider full or partial capture CCS to be BSER because of these technologies have not been adequately demonstrated and there are uncertainties

## Summary of Interagency Working Com ments on Draft Language under EO12866 Interagency Review.  Sub ject to Further Policy Review.

10 regarding the economic about technical feasibility and beca use of adverse impacts on electricity prices and the structure of the electric power sector.” o Page 265: “First, we do not consider that are uncertain as to whether full or partial capture CCS has been adequately demonstrated is technically feasible for this source category.” o Page 266. Recommend deleting paragraph beginning “Moreover, identifying partial or full CCS as the BSER for new stationary combustion turbines would have significant adverse effects on national electricity prices, electricity supply, and the structure of the power sector.” Please reconsider how the text here could adversely impact other current and future efforts to move the US toward developing additional CCS technologies relevant to natural gas and other industrial sources, and revise the language accordingly. This text should not foreclose on future regulatory rationales for technological advancements and GHG pollution reduction, as most of these will always have costs that will need to be weighed against the relevant benefits, at that time. We do not have sufficient information on the current cost of NG

‐ CCS, which is enough per se not to move ahead with this as BSER. In future, we may have adequate demonstrations and economic information, at which time EPA may choose to evaluate costs against the benefits of reducing the social cost of carbon and related impacts in reaching its future decision, rather than just “we cannot do it because it costs more.” o Page 266. EPA states: “We recognize that identifying full or partial CCS would as the BSER for this source category would result in significant emissions reductions, but at present, we already consider natural gas to be a low

‐ GHG

‐ emitting fuel and NGCC to be a low

‐ emitting technology.” Recommend replacing “this source category” with “new stationary combustion turbines.” o Powerpoint: “ we do not have the information to determine if it is technically feasible.” Reject CCS because it has not been adequately demonstrated.

Oil

‐ fired power plants:

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

‐ fired power plants under either the coal or natural gas NSPS requirements. Hence, Hawaiian power plants would not be included under the NSPS, and there would be no need for a non ‐ continental exclusion. However, no such exclusion or discussion is in the FR text, and the Da regulatory language relates to all burning of fossil fuels in steam generating units. The only discussions of oil fired power plants imply that these are included under the NSPS for steam and IGCC units (p. 2

‐ 3; footnote 3 on page 20 includes oil; p. 99 liquid fuels; p.103 fuel oil, appears linked to gas; p.108 oil

‐ fired exempt from acid rain program; p.119 “but not liquid

‐ fired sources”). There is no mention of Hawaii. Could EPA please clarify whether oil fired power plants are in the NSPS, and how the standard relates to Hawaii and non ‐ continental emission sources.

 Page 81, EPA states: “Note that we are not proposing standards for new steam generating units and stationary combustion turbines that sell less than 1/3 of their potential output to the grid, new non ‐ natural gas ‐ fired stationary combustion turbines, existing sources undertaking modifications or reconstructions, or certain projects under development as discussed below.” Can EPA provide an example of a “new non ‐ natural gas ‐ fired stationary combustion turbine?” Does this mean oil, and/or Hawaii, and how is this legally implemented in the Subpart Da and KKKK regulatory text sections?

## Summary of Interagency Working Com ments on Draft Language under EO12866 Interagency Review.  Sub ject to Further Policy Review.

11  Page 119, EPA states: “Rather, the EPA is simply promulgating new standards of performance for CO2 emissions from certain sets of sources, e.g., boilers and turbines, but not liquid

‐ fired sources.” How is such a “liquid

‐ fired source” exclusion implemented in the actual regulatory requirements under Da and KKKK?

Combined heat and power:

 The commenter supports appropriate incentives for combined heat and power (CHP) and suggests further consideration of its treatment under the rule to reflect associated emissions benefits.

Biomass:

 How does EPA propose to handle new fossil fuel

‐ fired power plants that also rely on some percentage of renewable fuel? What percentage of renewable biomass would be necessary to offset the GHG emission contributions of the fossil fuel to the GHG emissions rate, as measured by the facility?

 The commenter requests further consideration of the treatment of biomass emissions, particularly as it relates to the use of biomass co ‐ firing, to reflect its potential emissions benefits.

 How would biomass emissions be calculated for purposes of compliance with the NSPS? If that will be determined by EPA’s forthcoming rulemaking on biogenic carbon emissions for GHG permitting, should that be mentioned in the preamble?

 Notes from EPA’s oral presentation indicate that biomass is being treated the same as coal in these NSPS standards (p. 28). Does the recent court decision on biomass change this decision (URL below)? What plans does EPA have to develop a regulatory structure that would empower an appropriate use and consideration of the benefits of biomass power generation? http://www.eenews.net/greenwire/2013/07/15/stories/1059984404

PSD and Title V Program:

 The commenter recommends adding the language in redline to the following discussion (on page 262): “As noted in the ‘Implications for PSD and Title V programs’ section of this preamble, some states have authority to issue PSD permits. In other cases, the EPA issues the permit. States with approved permitting programs have some discretion in making permit decisions and including the necessary conditions of the permit to ensure the enforceability of the permit , subject to EPA’s oversight role

. Defendants in enforcement cases frequently raise “state permitting discretion” as a defense, so it would be useful to clarify this sentence about state discretion by mentioning EPA’s oversight role.” See, e.g. , Alaska Dept. of Environmental Conserv. v. EPA , 540 U.S. 461, 486 (2004) (affirming EPA’s “broad oversight role” for Best Available Control Technology determinations in the Prevention of Significant Deterioration (PSD) permitting process).

 The commenter recommends adding the language in redline to this discussion (on page 278): “Under the PSD program in part C of title I of the CAA, in areas that are classified as attainment

## Summary of Interagency Working Com ments on Draft Language under EO12866 Interagency Review.  Sub ject to Further Policy Review.

12 or unclassifiable for NAAQS pollutants, a new or modified source that emits any air pollutant subject to regulation at or above specified thresholds is required to obtain a preconstruction permit. This permit assures that the source meets specified requirements, including application and operation of best available control technology.” The new text recognizes that the PSD program also imposes operational obligations. Defendants sometimes latch onto the term “preconstruction” to argue that PSD obligations end after construction.

 In section IX.E “Implications for Title V fee requirements for GHGs” EPA proposes two options for how to account for the increased costs to states of reviewing and issuing permits to facilities that emit GHGs under the Title V program. However, the preamble does not provide enough information to allow the reader to compare the two proposals. Which is more likely to lead to states charging adequate fees? Which is more likely to appeal to states that do not wish to charge adequate fees?

Emissions Trading:

 Why not attempt to introduce trading emissions credits as a method of compliance? Is it clear, for example, that reducing GHG emissions by 30 percent from three EGUs is more expensive than reducing GHG emissions by 90 percent from one of the three (assuming each facility generates CO2 at the same rate)?

 EPA may wish to discuss whether emissions trading options would be economically efficient and legally possible in this regulation. While this rule is not expected to result in new compliance costs and therefore trading would not lower overall costs, we generally seek flexible mechanisms that have the potential to lower costs while providing the same environmental benefit.

From our reading, the preamble is silent to the concept of trading under section 111 of the Clean Air Act, though, to our knowledge, the courts have not explicitly ruled against it. One concern is that if trading would be a preferred option to address carbon emissions from existing sources, should this regulatory action do everything possible to enable that outcome? For example, if a trading system could be defined as the best system of emission reduction (BSER) for reducing carbon emissions from power plants, should that be defined here in the rule for new sources? Additionally, when and how would future power plants built to comply with these standards be re ‐ categorized existing sources, and would these plants be able to trade with existing sources under 111(d) if trading is not an option under 111(b)? As an illustration, we would assume that a new coal plant built with full CCS should be able to trade under an existing source trading program, would that be allowed if the standard for new sources doesn’t allow trading? Existing sources:

 Is it necessary for EPA to promulgate standards of performance for GHG emissions from new sources before the agency can legally promulgate standards of performance for GHG emissions from existing sources?

## Summary of Interagency Working Com ments on Draft Language under EO12866 Interagency Review.  Sub ject to Further Policy Review.

13  EPA’s discussion of BSER for coal continues to raise significant concerns about future actions as they relate to existing sources. Please provide further language to clarify EPA’s position regarding existing sources. For example, EPA asserts that “identifying partial CCS as the BSER for coal will be beneficial to coal

‐ fired electric generation

. . . .” (pp. 240), by eliminating uncertainty and forestalling future Federal controls that might require CCS. The logical implications of this statement and the subsequent discussion will be perceived as a threat of future requirements for existing sources. o Because the BSER for gas ‐ fired plants is NGCC without CCS, these plants must therefore “face the risk that future state or federal controls may require carbon capture, which

. . .

, is a particularly expensive proposition.” o If partial CCS now can forestall a “particularly expensive proposition” for future existing sources (that is, sources built now under the NSPS), then EPA appears to be saying that currently existing coal

‐ fired power plants also face the risk of future requirements for CCS. o EPA does not dispel the possibility that a partial CCS BSER now would be replaced with a full CCS requirement for future existing sources.

 Even though EPA states that this rule applies to newly constructed units, does EPA anticipate that the existing plants would face competitive pressures from the newly constructed units that will potentially be able supply energy more cheaply, effectively forcing the existing plants into upgrading their equipment which would mean they would also need to meet the new standard? If this is the case, EPA should take into account ex ‐ post compliance costs for the existing plants. Regulatory Impact Analysis: General comments

 Clarify language regarding environmental benefits

. Given that EPA is assuming the baseline and regulatory scenarios to be essentially equivalent, any language implying the draft rule will “limit” GHG emissions should be changed to state the rule is setting standards for emissions. “Limit” implies an incremental benefit resulting from the rule. See, e.g., first sentence of Sec. 1.1 in ES of RIA.

 Clarify baseline years and period of analysis. The RIA refers to a base year of 2020, achieving negligible changes by 2020, and an analysis period defined through 2022. Please clarify.

 What is the impact of the CSAPR legal decisions on the use of this rule in the baseline? Please clarify the role of CSAPR given its current status.

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

 Please review and, if appropriate, revise footnote 72, potentially substituting the term “justify” for the term “necessary” to make the language consistent with Executive Orders relevant to Benefit Cost considerations. EO 13563 reiterates EO 12866 that “each agency must, among other things: (1) propose or adopt a regulation only upon a reasoned determination that its benefits justify its costs (recognizing that some benefits and costs are difficult to quantify)

... (3) select, in choosing among alternative regulatory approaches, those approaches that maximize

## Summary of Interagency Working Com ments on Draft Language under EO12866 Interagency Review.  Sub ject to Further Policy Review.

14 net benefits (including potential economic, environmental, public health and safety, and other advantages; distributive impacts; and equity);”

State of CCS technology

 Chapter 4, clarify Sec.4.5 to reflect the current developmental state of CO2 control technology. EPA’s own BACT guidance and the NETL study both acknowledge the formative state of CCS technology. In addition, while IGCC projects are under development, only a handful of such plants currently exist in the world. The language in this section reads as if IGCC and CCS are well

‐ established and already in widespread commercial practice. Please provide further explanation. This discussion should list the exact number of completed plants currently employing the discussed technologies, the size/maximum capacity of these plants and allowable under current technology, any geographic limitations (such as altitude and temperature considerations for IGCC), projects currently in development, including those for which investment ceased, and plants with significant cost overrun issues. If the agency prefers, some of this detail could be presented in Chapter 5 of the RIA.

 Page 5

‐ 28. EPA assesses that any new coal

‐ fired plant that might be built could incorporate carbon capture technologies in a way that would not be cost

‐ prohibitive. Are there any existing coal

‐ fired plants that use carbon capture technology? How did EPA generate its estimate of the additional levelized cost of energy of CCS (p. 5

‐ 49)?

The RIA also states that 70% of the CCS projects underway plan to use the captured carbon for enhanced recovery of oil. Are any of these projects being implemented by coal

‐ fired plants?

 EPA’s analysis of cost and capacity suffer a significant selection bias because it relies on idealized and currently executed CCS projects and government economic incentives. (See RIA 5

‐ 7.) o Economic incentives for current CCS projects are not generalizable to the entire coal industry or into the future because these are limited to only certain firms in the following ways:

 Time: Significant funding for the economic incentives alluded to in the RIA come from legislation designed to stimulate the economy during a recessionary period by increasing spending in a specific time period. These incentives then are likely to expire as the economy improves.

 Eligible projects: tax benefits from the State of Texas for CCS projects were capped at the first three major projects to qualify for the benefits.

 Complex application processes: Department of Energy financial assistance and USDA CO2 capture project loans are limited to those who follow the necessary application process

 Limited funds: Department of Energy had a set amount of funds that they could use to incentivize projects as part of the Clean Coal Power Initiative Round III and therefore must prioritize its assistance

 Contrast: The incentives for nuclear power and other industries cited by EPA (see pp.226

‐ 7) are generally long

‐ standing and available to all firms in the industry, without application and not subject to appropriations. o EPA’s analysis of the feasibility and cost effectiveness of CCS technology centers on 2

‐ 3 specific examples of uncompleted CCS projects.

## Summary of Interagency Working Com ments on Draft Language under EO12866 Interagency Review.  Sub ject to Further Policy Review.

15  None of the CCS systems in active projects are fully running. These projects also have cost and schedule overruns that may contradict some of the EPA’s idealized estimates

 The Southern Kemper County Project is experiencing substantial cost overruns of hundreds of millions dollars

 The Texas Clean Energy Project (TCEP) was supposed to start construction in Fall 2011 but had not started as of March 2013

 The EPA is understating the amount of financial assistance that each of the CCS projects mentioned in the preamble is receiving. In addition to DOE cost sharing programs as part of the ARRA, these projects are receiving millions of dollars in Federal tax credits from the IRS as well as assistance from state and local governments

 For example, the TCEP has received $450 million (over a quarter of the projected project cost) in cost sharing from the DOE and an additional $100 million from the ARRA. TCEP also benefited from a limited Texas State law that provided over $100 million in tax benefits as well as additional tax benefits for EOR.

 By only looking at a couple of examples, the EPA is understating the overwhelming cost and risk factors that have forced previous government

‐ supported CCS projects to be de

‐ scoped, tabled, or shut down

 Of the 6 projects funded by the Department of Energy’s Clean Coal Power Initiative Round III half have been forced to withdraw from the program. According to the Congressional Research Service, these projects have significantly de

‐ scoped, tabled, or shut down due to cost overruns or uncertainty regarding the effectiveness and efficiency of the CCS technology. Natural Gas Price Assumptions

 Page 5

‐ 23 to 5

‐ 24. The regulatory impact analysis assess that for a new coal

‐ fired EGU without carbon capture to reach price parity with a natural gas EGU, the price of natural gas would have to rise to $10/MMBtu and that this price would exceed the most pessimistic forecast by about 30%. We understand that the forecasts include assumptions related to macroeconomic conditions, markets, etc. Would the model control for a shock to natural gas prices prompted by changes in U.S. export policy or trade policy?

For example, under current policy, liquefied natural gas (LNG) cannot be exported without a finding from the Department of Energy that such export is in the public interest. Exports to Free Trade Agreement partner countries are deemed automatically to be in the public interest. Should the U.S. successfully conclude the TransPacific Partnership (TPP) trade negotiations (with Japan as a TPP member and one of the world’s largest LNG importers) and/or trade negotiations with the EU, this would presumably lead to a large increase in exports to these regions. A study by DOE predicted that increased exports (resulting from current pending applications but not to future exports to new FTA partners) would increase the domestic price of LNG by $.22

– 1.11 (2010$/McF). Would such increases be accounted for in your model?

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

## Summary of Interagency Working Com ments on Draft Language under EO12866 Interagency Review.  Sub ject to Further Policy Review.

16 o According to the producer price index, real prices for energy have increased substantially since the time of the EPA’s analysis in the RIA. This development means that the EPA’s analysis will likely understate future energy price increases. o By largely representing a recessionary period, the EPA’s data reflects extraordinarily low electricity demand due to a contracting economy, a trend that has started to reverse itself as the economy moves out of the recession. Therefore, the EPA’s analysis will likely undervalue the future demand for electricity. o Natural gas prices are historically volatile. Where there has recently been some stability in prices this stabilization has occurred after the period of time that the EPA is analyzing in the RIA and should be taken into account as the EPA may understate future natural gas prices.

NETL study.

 EPA tabulates and relies primarily on NETL estimates of the LCOE for the various energy generation sources. We are more familiar with the annual EIA numbers, and these differ from the NETL values, for instance EIA (2013) estimates the LCOE for NGCC at $65.6/MWhr, whereas NETL/EPA estimate $52/MWhr. A number of the tables actually provide footnotes identifying the EIA numbers, which is very helpful. The recommendation is that such footnotes be provided once, early on, and with a brief explanation of why the numbers differ, beyond just the subtraction of the transmission cost estimates.

 Clarify NETL analysis as based on simulations/models and literature reviews and state key assumptions. Please see below for specific suggested further clarifications regarding the NETL study.

- Clarify NETL’s assessment of the analyzed technology. Please acknowledge in EPA’s discussion, the following NETL statements/findings. In addition, provide further explanation as to how EPA came to the conclusion that partial CCS is BSER (incl. emissions limit) given the NETL assessments. For example, have new facilities come on line since this study, or have new innovations occurred?

 Page 37, NETL. “The post

‐ combustion CO2 removal technology for the PC capture cases is immature technology. This technology remains unproven at commercial scale in power generation applications.”

 Page 37

‐ 38, NETL. “The pre ‐ combustion CO2 removal technology for the IGCC capture cases has a stronger commercial experience base. Pre

‐ combustion CO2 removal from syngas streams has been proven in chemical processes with similar conditions to that in IGCC plants, but has not been demonstrated in IGCC applications. While no commercial IGCC plant yet uses CO2 removal technology in commercial service, there are currently IGCC plants with CO2 capture well along in the planning stages.”

 Page 33

‐ 34, NETL. Environmental targets for IGCC were chosen to match EPRI’s design basis for Coal Fleet for Tomorrow Initiative. EPRI notes these designs are ‘targets’ and not to be used for permitting values. Further as of the report publication, NETL states there are 4 operating IGCC’s worldwide that use a solid feedstock and are primarily power producers (Polk, Wabash, Buggenum, & Puertollano). Further (p. 26, NETL), the NETL Aspen simulations assume zero elevation, which is optimal for IGCC performance.

## Summary of Interagency Working Com ments on Draft Language under EO12866 Interagency Review.  Sub ject to Further Policy Review.

17 - Clarify that ‘slip stream’ cost

‐ effectiveness was determined through literature review. (5

‐ 18) The RIA states that NETL determined the slip stream approach to be the most cost

‐ effective. At several points the NETL study (see, e.g., p. 2, 22, 77) states it made this determination via literature review. It should be made clear that this determination was not made through either simulation or direct analysis of data or actual case studies. Further EPA should state whether it has any actual data on the cost

‐ effectiveness of the slip stream approach. This might include noting whether the literature NETL reviewed used empirical data.

- Clarify expected accuracy of NETL estimates. Exhibit 2

‐ 15, p. 37 of the NETL study notes that cost estimates are expected to vary by ‐ 15% to ‐ 30% on the low side and ‐ 20% to +50% on the high side. This uncertainty should be reflected in the Chapter 5 tables.

- Clarify uncertainty of transportation (TS&M) estimates. P. 47, NETL. NETL states cost metrics for TS&M are “costs for a ‘favorable’ sequestration project, and may vary significantly based on variables such as terrain to be crossed by the pipelining, reservoir characteristics, and number of landowners from which sub

‐ surface rights must be acquired.” Further, NETL assumes transportation costs for the IL No. 6 coal will be 25% of mine mouth costs based on the Midwestern region with limestone available within a few states (Morgantown WV). Is this assumption applicable to costs in other regions of the US?

- Clarify cost assumptions regarding substitutability of NGCC, IGCC and coal w/partial CCS. Please provide further explanation for this assumption including citations where relevant. The NETL study EPA that references notes that simulations indicate electricity and capital costs for SC PC w/CCS v. GEE IGCC w/CCS vary according to level of CO2 capture. At lower levels, coal is cheaper for the owner with costs converging to roughly equivalent at above 90% capture. What levels of emissions/CO2 is EPA assuming when making this substitutability assumption?

- Clarify CSAPR/MATS v. NETL baselines. The NETL study assumes the 2006/2007 NSPS is in place but does not discuss CSAPR/MATS. Does EPA anticipate any significant tensions in these assumptions? Alternatively, did EPA make adjustments in IPM to accommodate the more current baseline? E.g. the NETL study assumes model plants use IL No. 6 high

‐ sulfur bituminous coal whereas CSAPR and MATS differ in both coal use (PRB) and transport assumptions. In addition, the RIA should add a footnote recognizing the recent CSAPR decision. While the analytics of the current legal environment would prove difficult to capture in the baseline, it is noteworthy that the decision found certain requirements to be too stringent for some states, which could (or not) in turn impact the level of control technology put in place.

- Clarify net capacity assumptions in relation to industry. The NETL study assumes 550 MWe for SC PC and a range of 523

‐ 622 MW for IGCC. How does this assumption relate to regulated entities? What, if any, technology limitations might exist for larger facilities?

- Clarify the impact of NETL’s within the fenceline assumption. While NETL considers capital and transport costs, these are limited to within the fenceline of the facility. Did EPA make any adjustments to its cost estimates for costs associated with pipeline investments and operating costs beyond the fenceline? If not, why? Is 50 miles/80km as assumed by NETL expected to be typical pipeline distance?

## Summary of Interagency Working Com ments on Draft Language under EO12866 Interagency Review.  Sub ject to Further Policy Review.

18 Paperwork Reduction Act

 This rule should impose no additional paperwork burden, since EPA asserts that this rule will have a negligible economic impact and a no “notable” CO2 emission reductions. o The PRA disfavors reporting and recordkeeping requirements intended simply to remind a regulated entity that substantive regulations exist. All information collections must have practical utility, which means the information gathered must be actually used rather than have a potential use. o If industry will proceed as it is, with or without the rule, EPA should eliminate any reporting or recordkeeping requirements associated with the NSPS, since there will be nothing to enforce. o CO2 emissions appear to be a function of the design of the electricity generating unit. Thus, if a new technology appears, CO2 emissions can be modeled as part of the existing permitting and reporting processes in place of emissions monitoring requirements. o For those units for which CCS can be operated at variable rates, existing GHG reporting requirements should be sufficient to ensure compliance with the NSPS. o Alternatively, all units subject to the NSPS should be exempted from the separate GHG reporting requirements. Editorial/technical comments: Preamble

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

‐ fired stationary combustion turbines?” This would appear to refer both to natural gas fired and coal fired power plants. However, the discussion in section 6 is limited to natural gas fired power plants.

 The commenter recommends the deletion of the text in strike out in the following sentence (on page 68): “A modification is ‘any physical change

. . . or change in the method of operation

. . . which increases the amount of any air pollutant emitted by such source or which results in the emission of any air pollutant not previously emitted,’ unless it is a specific type of change, exempt from consideration as a modification , such as installation of pollution control projects

. The validity of the pollution control project (PCP) exemption for NSPS has never been litigated, but it might be prudent to avoid highlighting the issue because the parallel PCP exemption for New Source Review was vacated in New York v. EPA , 413 F.3d 3 (D.C. Cir. 2005).

 Discussion of Coordination with Other Rules Applicable to Power Plants (page 74): The commenter recommends revision of this sentence as follows: “The EPA recognizes that it is important that each of these regulatory efforts achieves its intended environmental objectives in a common ‐ sense, cost

‐ effective manner that is consistent with the underlying statutory requirements and that minimize impacts on electricity rates and assure s a reliable power system.” Because the sentence already mentions that EPA is attempting to be “cost effective,” the reference to minimizing impacts on electric rates is redundant. Also, the commenter would prefer to avoid discussion of rate impacts because it is problematic for power plant enforcement. Utilities frequently raise rate impacts as a reason for delaying or avoiding compliance once they are found in violation of the CAA.

 EPA should add the language in redline to the following sentence (on page 114): “Therefore, with this 40 percent sales criterion on a single

‐ year basis, as a practical matter, it is anticipated

## Summary of Interagency Working Com ments on Draft Language under EO12866 Interagency Review.  Sub ject to Further Policy Review.

19 that few new simple cycle turbines would be subject to the proposed standards of performance.”

 Page 134. Please check latest estimates of sea level rise. The likely range for sea level between 2080 and 2100 from the AR5 is between 0.26m (10 inches) and 0.81m (31 inches) with most of the uncertainty having to do with emissions scenarios. Although higher than 7

– 23 inches, this is not “twice as large or more.”

 For consistency with the New Source Review Program, please substitute the following text in redline (on page 240): “In addition, identifying partial CCS as the BSER for coal will be beneficial to coal

‐ fired electric generation, and therefore fuel diversity, over the long term. This is because Identifying partial CCS as BSER eliminates uncertainty as to future control obligations for coal

‐ fired capacity. Any new coal

‐ fired source that constructs without CCS faces the risk that future state or federal controls may require carbon capture, which would require the source to retrofit CCS, which, in turn, is a particularly expensive proposition. This risk is heightened because power plants are generally long

‐ lived have expected lives of 30 to 40 years and the risk of future carbon limitations can be expected to remain throughout that period.”

 Page 273, in Discussion of Emission Rates for Smaller

‐ Size Units: Please ask EPA if there is a technical error in the following sentence so that the second use of “1000” should read “1100”: “Two of the small combined cycle facilities had a maximum 12

‐ operating

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

‐ operating

‐ month rolling average emissions rate equal to or greater than 1,000 lb CO2/MWh.” (The rule establishes an emissions limit of 1100 lb CO2/MWh for certain smaller units.) Regulatory Impact Analysis

 Page 4

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

 Page 5

‐ 1, second paragraph, last sentence before the bullet points: Should 2022 be 2020? We thought the analysis went through 2020 per page 1

‐ 2, which says every eight years is 2020.

 Page 5

‐ 2, drop “likely” from the phrase “the proposed EGU GHG NSPS would likely provide net social benefits” given that the benefit cost ratio is clearly positive under a wide range of assumptions.

 Page 5

‐ 2, middle of the page, second full paragraph, second sentence, part (3): should the word solid be added? On page 2

‐ 6, it appears that solid fossil

‐ fired EGUs are a separate category.

 Given that the rule extends to 2022, suggest EPA to include IPM projections for 2025 in addition to 2020 in Tables 5

‐ 1 and 5

‐ 3 to enhance clarity of information presentation. EPA could also consider including IPM results for 2030 to enhance comparison with AEO 2013 presented in the same tables.

 Page 5

‐ 34, clarify why the ratio of total CO2 emissions (3.0/2.7) is lower than the ratio of CO2 emissions rates (1,400/1,200), for the IGCC and SCPC, respectively. Also, drop “of these technologies” in paragraph 5.7.

## Summary of Interagency Working Com ments on Draft Language under EO12866 Interagency Review.  Sub ject to Further Policy Review.

20  Page 5

‐ 37, To avoid confusion, note in FN a that the updated SCC values were presented originally in the April 2013 TSI using 2007$.

 Page 5

‐ 42, In table 5

‐ X double check the valuations attached to the PM2.5 benefits since it is surprising that these are comparable to the CO2 related benefits, particularly since these estimates use the updated higher SCC values and reference new coal plants with relatively low PM emissions.

 Table on 5

‐ 44, second column. Should this show PM2.5 dis

‐ benefits? According to the table on pg 5

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

 Page 5

‐ 49, “To evaluate the potential revenues from EOR we estimate the revenue in each scenario if CO 2 could be sold for $20/ton based on [update source of estimate].” Yes, this is an important input number. Please update.

 Table 5

‐ X, p.5

‐ 49. The bottom line (last row) numbers in these tabulated calculations could be made a lot clearer by adding a plus sign before the right digits in the paired presentation. Currently, the text: << ‐ $7.1 ‐ $38 >> reads as if there are negative benefits (which is a bad thing) from negative seven to negative thirty

‐ eight dollars. Tracing the actual math leading to this reveals that the $38 is actually positive, hence the suggestion to affirmatively add the plus sign to << ‐ $7.1 ‐ +$38 >>. Same with the other columns.

Citations

 Page 40 Footnote 9, Page 130 Footnote 89 (Citation of the Coalition for Responsible Regulation Case): Here is the missing citation: Coalition for Responsible Regulation, Inc. v. Environmental Protection Agency, 684 F.3d 102 (D.C. Cir.), reh’g en banc denied, 2012 U.S. App. LEXIS 25997, 26313 (D.C. Cir. 2012), petitions for cert. filed, No. 12

‐ 1253 (U.S. Apr. 2013).

 Page 73 Footnote 61 (Citation of the Las Brisas Case): EPA may use this citation to the December 13, 2012 order: Las Brisas Energy Center, LLC v. Environmental Protection Agency, No. 12

‐ 1248, 2012 U.S. App. LEXIS 25535 (D.C. Cir. Dec. 13, 2012).

### Summary of Interagency Working Comments on Draft Language under EO12866 Interagency Review.  Subject to Further Policy Review.

EO 12866_EGU GHG NSPS 2060-AQ91 NPRM_20130628 6560-50-P

**ENVIRONMENTAL PROTECTION AGENCY**

**40 CFR Part 60 [EPA-HQ-OAR-2013-0495; FRL- ]**  **RIN 2060-AQ91**

**Standards of Performance for Greenhouse Gas Emissions from New Stationary Sources: Electric Utility Generating Units** 

**AGENCY:** Environmental Protection Agency (EPA).

**ACTION:** Proposed rule.

**SUMMARY:** On April 13, 2012, the EPA proposed a new source performance standard for emissions of carbon dioxide for new affected fossil fuel-fired electric utility generating units. The EPA received more than 2.5 million comments on the proposed rule. After consideration of information provided in those comments, as well as consideration of continuing changes in the electricity sector, the EPA determined that revisions in its proposed approach are warranted. Thus, in a separate action, the EPA is rescinding the April 13, 2012 proposal, and in this action, the EPA is proposing new standards of performance for new affected fossil fuel-fired electric utility steam generating units and stationary combustion turbines. This action proposes a separate standard of performance for fossil fuel-fired electric***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 2 of 403 utility steam generating units and integrated gasification combined cycle units that burn coal, petroleum coke and other fossil fuels that is based on partial implementation of carbon capture and storage as the best system of emission reduction. This action also proposes standards for natural gas-fired stationary combustion turbines based on modern, efficient natural gas combined cycle technology as the best system of

emission reduction.

**DATES:** Comments . The EPA previously proposed a new source performance standard for emissions of carbon dioxide (CO 2 ) for new affected fossil fuel-fired electric utility generating units (EGUs) on April 13, 2012 (77 FR 22392). The EPA considered comments submitted in response to the original April 13, 2012 proposal in developing this new proposal. However, we are rescinding the original proposal. If you would like consideration of comments submitted on the April 13, 2012 rulemaking, you should submit new comments or re-submit previous comments. Commenters who submitted public comments concerning any aspect of the previous proposal will need to consider the applicability of those comments to this current proposal and submit them again, if applicable, even if the comments are exactly or substantively the same as those previously submitted, to ensure consideration in the development of the final***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 3 of 403 rulemaking. Comments must be received on or before [INSERT THE

DATE 60 DAYS AFTER THE DATE OF PUBLICATION IN THE FEDERAL REGISTER OF THIS PROPOSED RULE]. Under the Paperwork Reduction Act (PRA), since the Office of Management and Budget (OMB) is required to make a decision concerning the information collection request between 30 and 60 days after [INSERT THE DATE OF PUBLICATION IN THE FEDERAL REGISTER OF THIS PROPOSED RULE], a comment to the OMB is best assured of having its full effect if the OMB receives it by [INSERT THE DATE 30 DAYS AFTER THE DATE OF PUBLICATION IN THE FEDERAL REGISTER OF THIS PROPOSED RULE]. Public Hearing . The EPA will hold a public hearing (or hearings) on this proposal. The date, time, and location of the public hearing (or hearings) will be announced separately in a subsequent Federal Register notice. Oral testimony will be limited to five minutes per commenter. The EPA encourages commenters to provide written versions of their oral testimonies either electronically or in paper copy. The rulemaking docket will include verbatim transcripts and written statements. If you would like to present oral testimony at one of the hearings, please notify Ms. Pamela Garrett, Sector Policies and Programs Division (C504–03), U.S. EPA, Research Triangle Park, NC 27711, telephone number (919) 541–7966; email: garrett.pamela@epa.gov. Persons wishing to provide testimony should notify Ms. Garrett***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 4 of 403 at least two days in advance of the public hearings. The public hearings will provide interested parties the opportunity to present data, views, or arguments concerning the proposed rule. EPA officials may ask clarifying questions during the oral presentations but will not respond to the presentations or comments at that time. Written statements and supporting information submitted during the comment period will be considered with the same weight as any oral comments and supporting information presented at the public hearing. For updates and additional information on the public hearings, please check the EPA’s website for this rulemaking, http://www.epa.gov/airquality/carbonpollutionstandards

. **ADDRESSES:** Comments . Submit your comments, identified by Docket ID No. EPA-HQ-OAR-2013-0495, by one of the following methods: At the website http://www.regulations.gov : Follow the instructions for submitting comments. At the website http://www.epa.gov/oar/docket.html : Follow the instructions for submitting comments on the EPA Air and

Radiation Docket web site.

E-mail : Send your comments by electronic mail (e-mail) to a-and-r-docket@epa.gov , Attn: Docket ID No. EPA-HQ-OAR-2013-

0495.

Facsimile : Fax your comments to (202) 566-9744, Attn:***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 5 of 403 Docket ID No. EPA-HQ-OAR-2013-0495.

Mail : Send your comments to the EPA Docket Center, U.S. EPA, Mail Code 2822T, 1200 Pennsylvania Ave., NW, Washington, DC 20460, Attn: Docket ID No. EPA-HQ-OAR-2013-0495. Please include a total of two copies. In addition, please mail a copy of your comments on the information collection provisions to the Office of Information and Regulatory Affairs, OMB, Attn: Desk Officer for EPA, 725 17 th St. NW, Washington, DC 20503. Hand Delivery or Courier : Deliver your comments to the EPA Docket Center, EPA West, Room 3334, 1301 Constitution Ave., NW,Room 3334, Washington, DC, 20460, Attn: Docket ID No. EPA-HQOAR-2013-0495. Such deliveries are accepted only during the Docket Center’s normal hours of operation (8:30 a.m. to 4:20 p.m., Monday through Friday, excluding federal holidays), and special arrangements should be made for deliveries of boxed

information.

Instructions : All submissions must include the agency name and docket ID number (EPA-HQ-OAR-2013-0495). The EPA’s policy is to include all comments received without change, including any personal information provided, in the public docket, available online at http://www.regulations.gov , unless the comment

includes information claimed to be Confidential Business Information (CBI) or other information whose disclosure is***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 6 of 403 restricted by statute. Do not submit information that you consider to be CBI or otherwise protected through http://www.regulations.gov or e-mail. Send or deliver information identified as CBI only to the following address: Roberto Morales, OAQPS Document Control Officer (C404-02), Office of Air Quality Planning and Standards, U.S. EPA, Research Triangle Park, North Carolina 27711, Attention Docket ID No. EPA-HQ-OAR-2013-0495. Clearly mark the part or all of the information that you claim to be CBI. For CBI information on a disk or CD-ROM that you mail to the EPA, mark the outside of the disk or CD-ROM as CBI and then identify electronically within the disk or CD-ROM the specific information you claim as CBI. In addition to one complete version of the comment that includes information claimed as CBI, you must submit a copy of the

comment that does not contain the information claimed as CBI for inclusion in the public docket. Information so marked will not be disclosed except in accordance with procedures set forth in 40 CFR part 2. The EPA requests that you also submit a separate copy of your comments to the contact person identified below (see **FOR FURTHER INFORMATION CONTACT).**  If the comment includes information you consider to be CBI or otherwise protected, you***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 7 of 403 should send a copy of the comment that does not contain the information claimed as CBI or otherwise protected. The www.regulations.gov website is an “anonymous access” system, which means the EPA will not know your identity or contact information unless you provide it in the body of your comment. If you send an email comment directly to the EPA without going through http://www.regulations.gov , your email address will be automatically captured and included as part of the comment that is placed in the public docket and made available on the Internet. If you submit an electronic comment, the EPA recommends that you include your name and other contactinformation in the body of your comment and with any disk or CDROM you submit. If the EPA cannot read your comment due to technical difficulties and cannot contact you for clarification, the EPA may not be able to consider your comment. Electronic files should avoid the use of special characters, any form of encryption, and be free of any defects or viruses.

Docket : All documents in the docket are listed in the http://www.regulations.gov index. Although listed in the index, some information is not publicly available (e.g., CBI or other information whose disclosure is restricted by statute). Certain other material, such as copyrighted material, will be publicly available only in hard copy. Publicly available docket materials***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 8 of 403 are available either electronically in http://www.regulations.gov or in hard copy at the EPA Docket Center, EPA West, Room 3334, 1301 Constitution Ave., NW, Washington, DC. The Public Reading Room is open from 8:30 a.m. to 4:30 p.m., Monday through Friday, excluding federal holidays. The telephone number for the Public Reading Room is (202) 566- 1744, and the telephone number for the Air Docket is (202) 566- 1742. Visit the EPA Docket Center homepage at http://www.epa.gov/epahome/dockets.htm for additional information about the EPA’s public docket. In addition to being available in the docket, an electronic copy of this proposed rule will be available on the Worldwide Web (WWW) through the Technology Transfer Network (TTN). Following signature, a copy of the proposed rule will be posted on the TTN’s policy and guidance page for newly proposed or promulgated rules at the following address: http://www.epa.gov/ttn/oarpg/

. **FOR FURTHER INFORMATION CONTACT:** Mr. Christian Fellner, Energy Strategies Group, Sector Policies and Programs Division (D243- 01), U.S. EPA, Research Triangle Park, NC 27711; telephone number (919) 541-4003, facsimile number (919) 541-5450; email address: fellner.christian@epa.gov or Dr. Nick Hutson, Energy Strategies Group, Sector Policies and Programs Division (D243-***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 9 of 403 01), U.S. EPA, Research Triangle Park, NC 27711; telephone number (919) 541-2968, facsimile number (919) 541-5450; email address: hutson.nick@epa.gov.

**SUPPLEMENTARY INFORMATION:** Acronyms . A number of acronyms and chemical symbols are used in this preamble. While this may not be an exhaustive list, to ease the reading of this preamble and for reference purposes, the following terms and acronyms are

defined as follows: AB Assembly Bill AEP American Electric Power AEO Annual Energy Outlook ANSI American National Standards Institute ASME American Society of Mechanical Engineers ASTM American Society for Testing of Materials BACT Best Available Control Technology BDT Best Demonstrated Technology BSER Best System of Emission Reduction Btu/kWh British Thermal Units per Kilowatt-hour Btu/lb British Thermal Units per Pound CAA Clean Air Act CAIR Clean Air Interstate Rule CBI Confidential Business Information CCS Carbon Capture and Storage (or Sequestration) CDX Central Data Exchange CEDRI Compliance and Emissions Data Reporting Interface CEMS Continuous Emissions Monitoring System CH 4 Methane CHP Combined Heat and Power CO 2 Carbon Dioxide CSAPR Cross-State Air Pollution Rule DOE Department of Energy DOT Department of Transportation ECMPS Emissions Collection and Monitoring Plan System EERS Energy Efficiency Resource Standards EGU Electric Generating Unit EIA Energy Information Administration EO Executive Order EOR Enhanced Oil Recovery***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 10 of 403 EPA Environmental Protection Agency FR Federal Register GHG Greenhouse Gas GW Gigawatts H 2 Hydrogen Gas HAP Hazardous Air Pollutant HFC Hydrofluorocarbon HRSG Heat Recovery Steam Generator IGCC Integrated Gasification Combined Cycle IPCC Intergovernmental Panel on Climate Change IPM Integrated Planning Model IRPs Integrated Resource Plans kg/MWh Kilogram per Megawatt-hour kJ/kg Kilojoules per Kilogram kWh Kilowatt-hour lb CO 2 /MMBtu Pounds of CO 2 per Million British Thermal Unit lb CO 2 /MWh Pounds of CO 2 per Megawatt-hour lb CO 2 /yr Pounds of CO 2 per Year lb/lb-mole Pounds per Pound-Mole MATS Mercury and Air Toxic Standards MMBtu/hr Million Metric British Thermal Units per Hour MW Megawatt MWe Megawatt Electric MWh Megawatt-hour N 2 O Nitrous Oxide NAAQS National Ambient Air Quality Standards NAICS North American Industry Classification System NAS National Academy of Sciences NETL National Energy Technology Laboratory NGCC Natural Gas Combined Cycle NRC National Research Council NSPS New Source Performance Standards NSR New Source Review NTTAA National Technology Transfer and Advancement Act O 2 Oxygen Gas OMB Office of Management and Budget PC Pulverized Coal PFC Perfluorocarbon PM Particulate Matter PM 2.5 Fine Particulate Matter PRA Paperwork Reduction Act PSD Prevention of Significant Deterioration PUC Public Utilities Commission RCRA Resource Conservation and Recovery Act RFA Regulatory Flexibility Act RGGI Regional Greenhouse Gas Initiative***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 11 of 403 RIA Regulatory Impact Analysis RPS Renewable Portfolio Standard SBA Small Business Administration SCC Social Cost of Carbon SCR Selective Catalytic Reduction SF 6 Sulfur Hexafluoride SIP State Implementation Plan SNCR Selective Non-Catalytic Reduction SO 2 Sulfur Dioxide SSM Startup, Shutdown, and Malfunction Tg Teragram Tpy Tons per Year TSD Technical Support Document TTN Technology Transfer Network UIC Underground Injection Control UMRA Unfunded Mandates Reform Act of 1995 U.S. United States USGCRP U.S. Global Change Research Program VCS Voluntary Consensus Standard WGS Water Gas Shift WWW Worldwide Web Organization of This Document . The information presented in this preamble is organized as follows:

I. General Information A. Executive summary B. Overview C. Does this action apply to me? II. Background A. Climate change impacts from GHG emissions B. GHG emissions from fossil fuel-fired EGUs C. The utility power sector and how its structure is changing D. Statutory background E. Regulatory and litigation background F. Coordination with other rulemakings G. Stakeholder input III. Proposed Requirements for New Sources A. Affected sources B. Emission standards C. Startup, shutdown, and malfunction requirements D. Continuous monitoring requirements E. Emissions performance testing requirements F. Continuous compliance requirements G. Notification, recordkeeping, and reporting requirements***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 12 of 403 IV. Rationale for Reliance on Rational Basis to Regulate GHGs from Fossil-fired EGUs A. Overview B. Climate Change Impacts from GHG Emissions; Amounts of GHGs from fossil fuel-fired EGUs C. CAA §111 requirements D. Interpretation of CAA §111 requirementsE. Rational basis to promulgate standards for GHGs from fossilfired EGUs F. Alternative findings of endangerment and significant contribution G. Comments on the state of the science of climate change V. Rationale for Applicability Requirements A. Applicability requirements - original proposal and comments B. Applicability requirements – today’s proposal C. Codification in the Code of Federal Regulations VI. Legal Requirements for Establishing Emission Standards A. Overview B. CAA requirements and Court interpretation C. Technical feasibility D. Factors to consider in determining the “best system” E. Nationwide component of factors in determining the “best system” F. Overall purposes G. Chevron framework H. Agency discretion I. Lack of requirement that standard be able to be met by all sources VII. Rationale for Emission Standards for New Fossil Fuel-fired Utility Boilers and IGCC Units A. Overview B. Identification of the best system of emission reduction C. Determination of the level of the standard D. Extent of reductions in CO 2 emissions E. Technical feasibility F. Costs G. Promotion of technology H. Nationwide, longer-term perspective I. Consistency with purposes of CAA section 111 J. Deference K. CCS and BSER in locations where costs are too high to implement CCS L. Compliance period M. Geologic sequestration VIII. Rationale for Emission Standards for Natural Gas-fired Stationary Combustion Turbines***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 13 of 403 A. Best system of emission reduction B. Determination of the standards of performance IX. Rationale for Other Requirements A. Compliance requirements X. Implications for PSD and Title V Programs A. Overview B. Applicability of tailoring rule thresholds under the PSD program C. Implications for BACT determinations under PSD D. Implications for title V program E. Implications for title V fee requirements for GHGs XI. Impacts of the Proposed Action A. What are the air impacts? B. What are the energy impacts? C. What are the compliance costs? D. How will this proposal contribute to climate change protection? E. What are the economic and employment impacts? F. What are the benefits of the proposed standards? XII. Request for Comments XIII. Statutory and Executive Order Reviews A. Executive Order 12866, Regulatory Planning and Review, and Executive Order 13563, Improving Regulation and Regulatory Review B. Paperwork Reduction Act C. Regulatory Flexibility Act as Amended by the Small Business Regulatory Enforcement Fairness Act of 1996, 5 U.S.C. 601 et seq . D. Unfunded Mandates Reform Act of 1995 E. Executive Order 13132, Federalism F. Executive Order 13175, Consultation and Coordination With Indian Tribal Governments G. Executive Order 13045, Protection of Children From Environmental Health Risks and Safety Risks H. Executive Order 13211, Actions Concerning Regulations That Significantly Affect Energy Supply, Distribution, or Use I. National Technology Transfer and Advancement Act J. Executive Order 12898, Federal Actions to Address Environmental Justice in Minority Populations and Low-Income Populations

**I. General Information** A. Executive summary***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 14 of 403 1. Purpose of the Regulatory Action On April 13, 2012, under the authority of Clean Air Act (CAA) section 111, the EPA proposed a new source performance standard to limit emissions of carbon dioxide (CO 2 ) from new fossil fuel-fired electric utility generating units, including, primarily, coal- and natural gas- fired units (77 FR 22392). After consideration of the information provided in more than 2.5 million comments on the proposal, as well as consideration of continuing changes in the electricity sector 1 , the EPA is issuinga new proposal to establish separate standards for fossil fuelfired electric steam generating units (utility boilers and IGCC units that use coal, petroleum coke and other fossil fuels) and for natural gas-fired stationary combustion turbines reflecting, respectively, a determination of the best system of emission reduction (BSER) for utility boilers and IGCC units and a BSER determination for natural gas-fired stationary combustion turbines. Because, in contrast, the April 2012 proposal relied on a single standard for all new fossil fuel-fired units, the EPA is issuing, as a final action, a notice (published separately in today’s Federal Register ) that rescinds the original proposal, as well as issuing this new proposal. 2. Summary of the Major Provisions This action proposes a separate standard of performance for Comment [A1]: This FN appears to be missing and/or is duplicative of the next FN, which is also labeled FN 1.

Comment [A2]: What other fossil fuels are referred to? It would improve clarity to be more specific.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 15 of 403 utility boilers and IGCC units based on partial implementation of carbon capture and storage as the best system of emission reduction. The proposed emission limit for those sources is 1,100 lb CO 2 /MWh. 1 This action also proposes standards of performance for natural gas-fired stationary combustion turbines based on modern, efficient natural gas combined cycle technology as the best system of emission reduction. The proposed emission limits for these sources are 1,000 lb CO 2 /MWh for larger units and 1,100 lb CO 2 /MWh for smaller units. At this time, the EPA is not proposing standards of performance for modified or

reconstructed sources.

3. Costs and Benefits As explained in the Regulatory Impact Analysis (RIA) for this proposed rule, available data indicate that, even in the absence of this rule, existing and anticipated economic conditions will lead electricity generators to choose new generation technologies that would meet the proposed standard without installation of additional controls. Therefore, based on the analysis presented in Chapter 5 of the RIA, the EPA projects that this proposed rule will result in negligible CO 2 emission changes, quantified benefits, and costs by 2020. These

1 In this rulemaking, all references to lb CO 2 /MWh are on a gross output basis, unless specifically noted otherwise.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 16 of 403 projections are in line with utility announcements and EIA modeling that indicate that coal units built between now and 2020 would have CCS, even in the absence of this rule. However, for a variety of reasons, some companies may consider coal units that the modeling does not anticipate. Therefore, in Chapter 5 of the RIA, we also present an analysis of the project-level costs of a new coal-fired unit with partial CCS alongside the project-level costs of a new coal-fired unit without CCS.

B. Overview

1. Why is the EPA issuing this proposed rule? Greenhouse gas (GHG) pollution threatens the American public's health and welfare by contributing to long-lasting changes in our climate that can have a range of negative effects on human health and the environment. The impacts could include: longer, more intense and more frequent heat waves; more intense precipitation events and storm surges; less precipitation and more prolonged drought in the West and Southwest; more fires and insect pest outbreaks in American forests, especially in the West; and increased ground level ozone pollution, otherwise known as smog, which has been linked to asthma and premature death. Health risks from climate change are especially serious for children, the elderly and those with heart and respiratory problems.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 17 of 403 The U.S. Supreme Court ruled that GHGs meet the definition of “air pollutant” in the Clean Air Act (CAA or Act), and this decision clarified that the Act’s authorities and requirements apply to GHG emissions. Unlike most other air pollutants, GHGs may persist in the atmosphere from decades to millennia, depending on the specific greenhouse gas. This special characteristic makes it crucial to take initial steps now to limit GHG emissions from fossil fuel-fired power plants, specifically emissions of carbon dioxide (CO 2 ), since they are the nation’s largest sources of carbon pollution. This rule will ensure that the next generation of fossil fuel-fired power plants in this country will use modern technologies that limit harmful carbon pollution. On April 13, 2012, the EPA issued a proposed rule to limit GHG emissions from fossil fuel-fired power plants byestablishing a single standard applicable to both natural gasand coal-fired generating units. After consideration of the information provided in more than 2.5 million comments on the proposal, as well as consideration of continuing changes in the electricity sector 2 , the EPA is issuing a new proposal to

2 For example, since April 2012, there has been significant progress on two CCS projects (Kemper County and Boundary Dam), and they are now both over 75 percent complete. Two other projects have continued to make progress toward breaking ground***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 18 of 403 establish separate standards for fossil fuel-fired electric steam generating units (utility boilers and IGCC units) and for natural gas-fired stationary combustion turbines reflecting, respectively, a determination of the best system of emission reduction (BSER) for utility boilers and IGCC units that use coal, petroleum coke and other fossil fuels, and a BSER determination for natural gas-fired stationary combustion turbines. Because, in contrast, the April 2012 proposal relied on a single standard for all new fossil fuel-fired units, the EPA is issuing, as a final action, a notice (published separately in today’s Federal Register ) that rescinds the original proposal, as well as issuing this new proposal.

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

CO 2 emissions? Congress established requirements under section 111 of the 1970 Clean Air Act to control air pollution from new stationary sources through new source performance standards (NSPS). Specifically, section 111 requires the EPA to set technology-based standards for new stationary sources to minimize emissions of air pollution to the environment. For more than four decades, the EPA has used its authority under section

(Texas Clean Energy Project and Hydrogen Energy California Project).***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 19 of 403 111 to set cost-effective emission standards that ensure newly constructed sources use the best performing technologies to limit emissions of harmful air pollutants. In this proposal, the EPA is following the same well-established, customary interpretation and application of the law under section 111 to address GHG emissions from new fossil fuel-fired power plants. 3. What sources should the EPA include as it develops proposed standards for GHGs for power plants? Before determining the appropriate technologies and levels of control that represent BSER for greenhouse gas emissions, the EPA must first identify the appropriate sources to control. The logical starting point is to consider whether, given current trends concerning coal-fired and natural gas-fired power plants and the nature of GHGs, the EPA’s current NSPS regulatory structure is appropriate. The EPA’s NSPS regulations already regulate conventional pollutants from these sources under two 40 CFR part 60 subparts: subpart Da, electric utility steam generating units, which includes both steam electric utility boilers and integrated gasified combined cycle (IGCC) units, and subpart KKKK, stationary combustion turbines, which includes both simple cycle and combined cycle stationary combustion

turbines.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 20 of 403 For sources covered under subpart Da, the original proposal relied on analysis, primarily undertaken by EIA, indicating that, while substantial reliance on coal-fired electricitygeneration would continue in the future, few, if any, new coalfired power plants were likely to be built by 2025. Based in

part on these results, the EPA concluded that it was appropriate to propose a single fuel-neutral standard covering all intermediate and baseload units based on the performance of recently constructed natural gas combined cycle (NGCC) units. In light of developments in the electricity sector since the April 2012 proposal, and in response to numerous comments on the proposal itself, the EPA is changing the approach in today's notice and proposing to set separate standards for sources covered by this subpart. 3 The EPA notes that, since the original proposal, a few coal-fired units have reached the advanced stages of construction and development, which suggests that proposing a separate standard for coal-fired units is appropriate. Since the proposal, progress on Southern Company's Kemper County Energy Facility, which will deploy IGCC with partial CCS, has continued, and the project is now over 75 percent complete.

3 While the emphasis of EPA’s BSER determination is on coal- and petcoke-fired units, the subpart covers all fossil fuel-fired EGU boilers and IGCC units, including those burning oil and gas. Comment [A3]: Without CCS, right? Aren’t a few with CCS projected to be built? Comment [A4]: This wasn’t the entire basis for the previous conclusion that a single standard was appropriate. EPA also considered that NGCC was available to meet the needs for baseload power and, that, even if a coal plant were built, CCS would be an option. “Based on these results” here suggests that that justification was thinner than it actually was.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 21 of 403 Additionally, two other projects, Summit Power's Texas Clean Energy Project (TCEP) and the Hydrogen Energy California Project (HECA) – both of which will deploy IGCC with CCS – continue to move forward. Continued progress on these projects is consistentwith the EIA modeling which projects that few, if any, new coalfired EGUs would be built in this decade and that those that are

built would have CCS. 4 The existence and apparent ongoing viability of these IGCC projects with CCS justify a separate

BSER determination for coal-fired and other solid fossil fuelfired (e.g., petroleum coke) power plants In addition to these projects, a number of commenters noted that, if natural gas prices increase, there could be greater interest in the construction of additional coal-fired generation capacity. This, too, is consistent with the EIA analysis, which also suggests that, in a limited number of potential scenarios generally associated with both significantly higher than anticipated electric demand and significantly higher than expected natural gas prices, some additional new coal-fired generation capacity may be built beyond 2020. It is also

4 Even in its sensitivity analysis, the EIA does not project any additional coal projects beyond its reference case until 2023, in a case where power companies assume no emission limitations for GHGs, and until 2025 in any sensitivity analysis in which there are emission limitations for GHGs.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 22 of 403 consistent with publicly available electric utility Integrated Resource Plans (IRPs) 5

. Many of those IRPs indicated the utilities’ interest in developing some amount of generating capacity using other intermediate-load and baseload technologies, in addition to new NGCC capacity, to meet future demand (albeit, almost always at a higher cost than NGCC technology). Only a few utilities’ IRPs indicated that new coal-fired generation without CCS was a technology option that they were seriously considering to meet that demand. Finally, a number of commenters suggested that it was important to set standards that preserve options for fuel diversity, particularly if natural gas prices exceed projected levels. Given this information, the EPA believes that it isappropriate to set a separate standard for solid fossil fuelfired EGUs, both to address the small number of coal plants that evidence suggests might get built and to set a standard that is robust across a full range of possible futures in the energy and electricity sectors. Utility announcements (about the status of coal projects), IRPs, and EIA projections suggest that, by far, the largest

5 IRPs are planning documents that many Public Utility Commissions require utilities to file outlining their plans to meet future demand. Many of the IRPs that the EPA has reviewed included planning horizons of ten years or more.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 23 of 403 sources of new fossil fuel-fired electricity generation are likely to be natural gas-fired combined cycle (NGCC) units. The EPA believes, therefore, that it is also appropriate to set a standard for stationary combustion turbines used as EGUs. These units are covered under subpart KKKK (stationary combustion turbines). The EPA also proposes to maintain the definition of EGUs under the NSPS that differentiates between EGUs (sources used primarily for generating electricity for sale to the grid) and non-EGUs (turbines primarily used to generate steam and/or electricity for on-site use). That definition defines EGUs as units that sell more than 1/3 of their potential electric output to the grid. Under this definition, most simple cycle “peaking” stationary combustion turbines, which typically sell significantly less than 1/3 of their potential electric output to the grid, would not be affected by today’s proposal. Finally, the EPA is not proposing standards today for one conventional coal-fired EGU project which, based on current information, appears to be the only such project under development that has an active air permit and that has not already commenced construction for NSPS purposes. If the EPA determines that the project is truly proceeding, it will propose***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 24 of 403 a standard for that source at the time the EPA finalizes today’s proposed rule.

4. What is the EPA’s general approach to setting BSER standards for new sources under Section 111(b)? Section 111(b) requires the EPA to identify the “best system of emission reduction....adequately demonstrated” (BSER) available to limit pollution. The CAA and subsequent court decisions identify the factors for the EPA to consider in a BSER determination. For this rulemaking, the following factors are key: feasibility, costs, size of reductions and technology. **Feasibility:** The EPA considers whether the system of emission reduction is technically feasible.

**Costs:** The EPA considers whether the costs of the system

are not unreasonable.

**Size of reductions:** The EPA considers the amount of emissions reductions that the system would generate. **Technology:** The EPA considers whether the system promotes the implementation and further development of technology. After considering these four factors, we propose to find partial implementation of carbon capture and storage (CCS) technology to be the BSER for new affected fossil fuel-fired boilers and IGCC units (subpart Da sources) and modern,

efficient NGCC units to be the BSER for new affected combustion Comment [A5]: It would improve clarity by adding a footnote with references and a summary of the court decisions.

Comment [A6]: suggest to change “find” to “define,” or revise the sentence to “..., we propose that partial implementation of carbon capture and storage (CCS) technology to be the BSER...”***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 25 of 403 turbines (subpart KKKK sources). The foundations for these

determinations are described in sections VII and VIII.

5. What is BSER for fossil fuel-fired boilers and IGCC units? Power generated from the combustion or gasification of coal

emits more CO 2 than power generated from the combustion of natural gas or by other means, such as non-emitting solar or wind. If any new coal-fired unit is built, its CO 2 emissions would be significantly greater than a comparably sized NGCC unit. Thus, it is important to set a standard for any new coal plant that might be built.

The three alternatives the EPA considered in the BSER analysis for new fossil fuel-fired utility boilers and IGCC units are: (1) highly efficient new generation that does not include CCS technology, (2) new generation with “full capture” CCS and (3) new generation with “partial capture” CCS. Generation technologies representing enhancements inoperational efficiency (e.g., supercritical or ultrasupercritical coal-fired boilers or IGCC units) are clearly technically feasible and present little or no incremental cost compared to the types of technologies companies weighing new coal-fired generation without CCS are considering. However, they do not provide meaningful reductions in CO 2 emissions from new sources. Efficiency-improvement technologies alone result in Comment [A7]: Is non-emitting completely accurate? Suggest rephrasing as low emitting. Comment [A8]: It could be helpful to provide numeric magnitude of differences, such as adding “...significantly greater (e.g., X%-X%) than a comparable sized NGCC unit.”***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 26 of 403 only very small reductions in CO 2 emissions, especially in contrast to those achieved by the application of CCS. Determining that these high-efficiency generating technologies represent the BSER for CO 2 emissions from coal-fired generation would fail to promote the development and deployment of CO 2 pollution-reduction technology from power plants. In fact, a finding that this efficiency-enhancing technology alone, as opposed to CCS, is the BSER for CO 2 emissions from coal-fired generation likely would inhibit the development of technology

that could reduce CO 2 emissions significantly, thus defeating one of the purposes of the CAA's NSPS provisions. For example, during its pilot-scale CCS demonstration at the Mountaineer Plant in New Haven, WV, American Electric Power (AEP) placed announced in [insert year] that it was placing ed on hold its plans to scale-up the CCS system, citing the uncertain status of U.S. climate policy as a contributor to its decision. Reflecting An assessment of the t T he technical feasibility and availability of CCS , indicates that at least half of the coal-fired power plants that are currently under development are designed to use some type of CCS. In most cases, the projects will sell or use the captured CO 2 as to generate additional revenue. These projects include: Comment [A9]: Again, would be helpful to give numeric examples, such as the range of percentage reductions in CO2 emissions.

Comment [A10]: Suggested edits to enhance clarity.

Comment [A11]: Perhaps “determination” is more appropriate.

Comment [A12]: Perhaps change to “a key contributing factor”?

Comment [A13]: Does EPA know if all of the planned projects intend to generate revenues from captured CO2, which seems to be what a company would want to do to improve the economics of a CCS project? Can EPA explain the difference between “sell” and “use”?***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 27 of 403 **Southern Company’s Kemper County Energy Facility** , a 582 MW IGCC power plant that is currently under construction in Kemper County, Mississippi. The plant will include, with some financial assistance from DOE, a CCS system designed to capture approximately 65 percent of the produced CO 2 . **Texas Clean Energy Project (TCEP),** an IGCC plant near Odessa, Texas, that is under development by the Summit Power Group, Inc. (Summit). TCEP is a 400 MW IGCC plant that expects to capture approximately 90 percent of the produced CO 2 . **Hydrogen Energy California, LLC (HECA),** is proposing to build a plant similar to TCEP in western Kern County, California. The HECA plant is an IGCC plant fueled by coal and petroleum coke that will produce 300 MW of power and will capture CO 2 for use in enhanced oil recovery (EOR) operations. They expect to capture approximately 90 percent of the produced CO 2 . The above examples suggest that project developers who are incorporating CCS generally considered two variants: either a partial CCS system, or a full CCS system. Therefore, the EPA considered both “full capture” and “partial capture” CCS technologies.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 28 of 403 Coal plants implementing “full capture” CCS plan to achieve large reductions in CO 2 pollution - usually 90 percent or more, though it is not clear whether the units being developed today will be able to achieve full capture at the outset

. . In assessing whether the cost of a certain option is not unreasonable, the EPA first considered the appropriate frame of

reference referenc . Power companies often choose the lowest cost form of generation when determining what type of new generation to build. Based both on the EIA modeling and utility IRPs, there appears to be a general acceptance that the lowest cost form of

new power generation is NGCC. Many states find value in coal investments and have policies and incentives to encourage coal energy generation. Utility IRPs (as well as comments on the April 2012 proposal) suggest that many companies also find value in other factors, such as fuel diversity, and are often willing to pay a premium for it. Utility IRPs suggest that a range of technologies can meet this preference, including coal without CCS, coal with CCS and nuclear. Biomass-fired power generation and geothermal power generation are other technologies that are dispatchable and that could potentially meet this objective. These technologies all cost significantly more than natural gas-fired generation, which ranges from $52/MWh to $86/MWh, depending upon assumptions about Comment [A14]: This statement should further clarify whether these facilities will, at a minimum, achieve “partial capture” at the outset. Comment [A15]: Is EPA confident on this statement? Will this be read as EPA casting doubt on the viability of the project TCEP or HECA project?

Comment [A16]: Suggested edit to enhance clarity.

Comment [A17]: It would be helpful to add some language to clarify whether these technologies are comparable, i.e., are these technologies used to serve base-load and intermediate loads, and would they have comparable generation capacity? Comment [A18]: Are these LCOE estimates? Should probably specify.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 29 of 403 natural gas prices. In assessing whether the cost of coal with CCS would have an unreasonable impact on the cost of power generation, the EPA believes it is appropriate to compare coal with CCS to this range of non-natural gas-fired electricity generation options. Based on data from the EIA and the DOE National Energy and Technology Laboratory (NETL), the EPA believes that the cost of technologies other than coal with CCS and NGCC range from $80/MWh to $130/MWh. These include nuclear at $103/MWh to $114/MWh, biomass at $97/MWh to $130/MWh, and geothermal at $80/MWh to $99/MWh. The cost of “full capture” CCS mi t l i t g ates against determining that it is the BSER for CO 2 emissions for coal-fired power plants. The EPA projects the levelized cost of electricity of generation technologies with full capture to be in the range of $136/MWh to $147/MWh. Because ”full capture” CCS costs without EOR are significantly above the price range of potential alternative generation options, the EPA believes that full capture CCS does not meet the cost criterion of BSER. Finally, the EPA considered whether implementation of “partial capture” CCS should be proposed to be BSER for new fossil fuel-fired utility boilers and IGCC units. Partial capture CCS has been implemented successfully in a number of facilities over many years. The Great Plains Synfuels Comment [A19]: Are these “levelized” costs?

Comment [A20]: Are these LCOE estimates? Should probably specify.

Comment [A21]: Without EOR, right? Should specify in this sentence.

Comment [A22]: Could EPA please provide estimated levelized costs for full capture project with EOR revenue and compare with other forms of generation? As stated above, CCS+EOR appears to be most likely scenario, an assessment of the economics of CCS+EOR scenario is more relevant.

Comment [A23]: Are there any international facilities that can be referenced here?***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 30 of 403 Facility 6 is a coal gasification facility that has captured at least 50 percent of its produced CO 2 for use in enhanced oil recovery (EOR) operations since 2000. Projects such as AEP Mountaineer have successfully demonstrated the performance of partial capture CCS on a significant portion of their exhaust stream. The Southern Company Kemper County Energy Facility will use partial CCS to capture approximately 65 percent of the produced CO 2 for use in nearby EOR operations. The facility is now more than 75 percent complete and is expecting to begin operation in 2014. When considered against the range of costs that would be incurred by projects deploying non-natural gas-fired electricity generation, the implementation costs of partial CCS are, clearly, not unreasonable. The EPA analysis shows that the costs of partial CCS are comparable to costs of other non-NGCC generation. The EPA projects levelized costs of electricity generation ranging from $92/MWh to $110/MWh, depending upon assumptions about technology choices and the amount, if any, of

revenue from sale of CO 2 for EOR. This range compares to levelized costs in a range of $80/MWh to $130/MWh for various

6 While this facility is not an EGU, it has significant similarities to a coal gasification combined cycle EGU, and the implementation of the partial CCS technology would be similar enough for comparison. Comment [A24]: This conclusion would fit more appropriately at the end of the paragraph. Without reading the LCOE information, it is not “clearly, not unreasonable”***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 31 of 403 forms of other non-natural gas-fired electricity generation. These include nuclear at $103/MWh to $114/MWh, biomass at $97/MWh to $130/MWh, and geothermal at $80/MWh to $99/MWh. The projects in development for new coal-fired generation are few in number, and most would already meet an emission limit based on implementation of partial CCS. As a result, a standard based on partial CCS would not have a significant impact on nationwide energy prices. Moreover, the fact that IGCC developers could meet the requirements of the standard through the use of a more conventional turbine (syngas turbine, rather than a more advanced hydrogen turbine) reinforces both the technical feasibility and cost basis of the EPA’s proposal to determine that CCS with partial capture is the BSER. Partial CCS (designed to meet an emission standard of 1,100

lb CO 2 /MWh) would also achieve significant emission reductions, emitting on the order of 30 to 50 percent less CO 2 than a coalfired unit without CCS. Finally, a partial CCS requirement clearly promotes CCS technologies, and does so as much as a standard based on a full capture CCS requirement would. After conducting a BSER analysis of the three options described above, the EPA proposes that new fossil fuel-fired utility boilers and IGCC units implementing partial CCS best meets the requirements for BSER. It ensures that any new fossil Comment [A25]: Suggest moving this information above (see insert) to improve clarity.

Formatted: Subscript***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 32 of 403 fuel-fired utility boiler or IGCC unit will achieve meaningful

emission reductions in CO 2, and it will also encourage greater use, development, and refinement of CCS technologies. CCS technology has been adequately demonstrated, and its implementation costs are reasonable. Therefore, the EPA is basing the standards for new fossil fuel-fired utility boilers and IGCC units on partial carbon capture and storage (CCS) technology operating to a level of 1,100 lb CO 2 /MWh.

6 **.** What is BSER for fossil fuel-fired stationary combustion

turbines? We considered two alternatives in evaluating the BSER for new fossil fuel-fired stationary combustion turbines: (1) modern, efficient NGCC units and (2) modern, efficient NGCC

units with CCS.NGCC units are the most common type of new fossil fuelfired units being planned and built today. The technology is in wide use. Nearly all new fossil fuel-fired EGUs being constructed today are using this advanced, efficient system for generating intermediate and baseload power. Importantly, NGCC is an inherently lower CO 2 -emitting technology. Almost every natural gas-fired stationary combined cycle unit built in the U.S. in the last five years emits approximately 50 percent less CO 2 per MWh than a typical new coal-fired plant of the same size. The***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 33 of 403 design is technically feasible, and evidence shows that NGCC units are currently the lowest-cost, most efficient option for new fossil fuel-fired power generation. By contrast, NGCC with CCS is not a configuration that is widely being planned and built today. The EPA considered whether NGCC with CCS could be identified as the best system of emission reductions adequately demonstrated for new stationary combustion turbines, and we decided that it could not be identified for several reasons. At this time, CCS has not been implemented for NGCC units, and we believe there is insufficient information to make a determination regarding the technical feasibility of implementing CCS at these types of units. The EPA is aware of only one NGCC unit that has implemented CCS on a very small portion of its exhaust stream. The EPA is not aware of any demonstrations of NGCC units implementing CCS technology that would justify setting a national standard. Further, the EPA does not have sufficient information on the prospects of transferring the coal-based experience with CCS to NGCC units. In fact, CCS technology has primarily been applied to gas streams that have a relatively high to very high concentration of CO 2 (such as that from a coal combustion or coal gasification unit). The

concentration of CO 2 in the flue gas stream of a coal combustion unit is normally about four times higher than the concentration Comment [A26]:

Comment [A27]: Is it a question of technical feasibility, as in, whether it is technically feasible to implement CCS with NGCC, or is it a question of overall likelihood that CCS would be implemented with NGCC. Are there are technical constraints to actually using CCS in the NGCC context? Or, are there financial and efficiency drivers involved?***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 34 of 403

of CO 2 in a natural gas-fired unit. Natural gas-fired stationary combustion turbines also operate differently from coal-fired

boilers and IGCC units of similar size. The NGCC units are more easily cycled (i.e., ramped up and down as power demands increase and decrease). This cyclical operation, combined with the already low concentration of CO 2 in the flue gas stream, lead to uncertainty about how technically feasible CCS technology is

for NGCC units absent further information. After considering both technology options, the EPA is proposing to find modern, efficient NGCC technology to be the BSER for stationary combustion turbines, and we are basing the proposed standards on the performance of recently constructed NGCC units. The EPA is proposing that larger units be required to meet a standard of 1,000 lb CO 2 /MWh and that smaller units (typically slightly less efficient, as noted in comments on the original proposal) be required to meet a standard of 1,100 lb

CO 2 /MWh. 7. What is the organization and approach for the proposal? This action presents the EPA’s proposed approach forsetting standards of performance for new affected fossil fuelfired electric utility steam generating units (utility boilers) and stationary combustion turbines. The rationale for regulating GHG emissions from the utility power sector, including related Comment [A28]: Are there references to support these statements?***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 35 of 403 regulatory and litigation background and relationship to other rulemakings, is presented below in section II. The specific proposed requirements for new sources are described in detail in

section III. The rationale for reliance on a rational basis to regulate GHG emissions from fossil fuel-fired EGUs is presented in section IV, followed by the rationale for applicability requirements in section V. The legal requirements for establishing emission standards are discussed in detail in

section VI. Sections VII and VIII describe the rationale for each of the proposed emission standards, including anexplanation of the determination of BSER for new fossil fuelfired utility boilers and IGCC units and for natural gas-fired stationary combustion turbines, respectively. Rationale for other proposed requirements is discussed in section IX. Implications for PSD and title V programs are described in section X, and impacts of the proposed action are described in section XI. In section XII, the agency specifically requests comments on the proposal. A discussion of statutory and executive order reviews is provided in section XIII. Also published today in the Federal Register is the notice rescinding the original April 13, 2012 proposal. Today’s proposal outlines an approach for setting standards of performance for emissions of carbon dioxide for new affected Comment [A29]: Spell out when it first appears.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 36 of 403 fossil fuel-fired electric utility steam generating units (utility boilers) and stationary combustion turbines. C. Does this action apply to me? The entities potentially affected by the proposed standards

are shown in Table 1 below. **Table 1. Potentially Affected Entities a** 

**Category NAICS**  **Code Examples of Potentially Affected**  **Entities**

Industry 221112 Fossil fuel electric power generating u nits.

Federal Government 221112 b Fossil fuel electric power generating units owned by the federal government.

State/Local Government 221112 b Fossil fuel electric power generating units owned by municipalities.

Tribal Government 921150 Fossil fuel electric power generating units in Indian Country.

a Include Includes NAICS categories for source categories that own and operate electric power generating units (including boilers and stationary combined cycle combustion turbines). b Federal, state, or local government-owned and operated establishments are classified according to the activity in which they are engaged. This table is not intended to be exhaustive, but rather to provide a guide for readers regarding entities likely to be affected by this proposed action. To determine whether your facility, company, business, organization, etc., would be***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 37 of 403 regulated by this proposed action, you should examine the applicability criteria in 40 CFR 60.1. If you have any questions regarding the applicability of this action to a particular entity, consult either the air permitting authority for the entity or your EPA regional representative as listed in 40 CFR 60.4 or 40 CFR 63.13 (General Provisions). **II. Background** In this section we discuss climate change impacts from GHG emissions, both on public health and public welfare, and the science behind the agency’s conclusions. We present information about GHG emissions from fossil-fuel fired EGUs, and we describe the utility power sector and its changing structure. We then provide the statutory, regulatory, and litigation background for this proposed rule. We close this section by discussing how this proposed rule coordinates with other rulemakings and describing actions to obtain stakeholder input on this topic and the original proposed rule. A. Climate change impacts from GHG emissions In 2009, the EPA Administrator issued the document we refer to as the Endangerment Finding under CAA section 202(a)(1). 7 In the Endangerment Finding, which focused on public health and

7 “Endangerment and Cause or Contribute Findings for Greenhouse Gases Under Section 292(a) of the Clean Air Act,” 74 Fed. Reg. 66,496 (Dec. 15, 2009) (“Endangerment Finding”).***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 38 of 403 public welfare impacts within the United States, the

Administrator found that elevated concentrations of GHGs in the atmosphere may reasonably be anticipated to endanger public health and welfare of current and future generations. We summarize these adverse effects on public health and welfare briefly here and in more detail in the RIA. 1. Public health impacts detailed in the 2009 Endangerment Finding Anthropogenic emissions of GHGs and consequent climate change threaten public health in multiple aspects. By raising average temperatures, climate change increases the likelihood of heat waves, which are associated with increased deaths and illnesses. While climate change also leads to reductions in cold-related mortality, evidence indicates that the increases in heat mortality will be larger than the decreases in cold mortality. Climate change is expected to increase ozone pollution over broad areas of the country, including large population areas with already unhealthy surface ozone levels, and thereby increase morbidity and mortality. Other public health threats also stem from increases in intensity or frequency of extreme weather associated with climate change, such as increased hurricane intensity, increased frequency of intense storms and heavy precipitation. Increased coastal storms***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 39 of 403 and storm surges due to rising sea levels are expected to cause increased drownings and other health impacts. Children, the elderly, and the poor are among the most vulnerable to these

climate-related health effects. 2. Public welfare impacts detailed in the 2009 Endangerment Finding Anthropogenic emissions of GHGs and consequent climate change also threaten public welfare in multiple aspects. Climate changes is expected to place large areas of the country at serious risk of reduced water supplies, increased water pollution, and increased occurrence of extreme events such as floods and droughts. Coastal areas are expected to face increased risks from storm and flooding damage to property, as well as adverse impacts from sea level rise, such as land loss due to inundation, erosion, wetland submergence and habitat loss. Climate change is expected to result in an increase in peak electricity demand, and extreme weather from climate change threatens energy, transportation, and water resource infrastructure. Climate change may exacerbate ongoing environmental pressures in certain settlements, particularly in Alaskan indigenous communities. Climate change also is very likely to fundamentally rearrange U.S. ecosystems over the 21 st century. Though some benefits may balance adverse effects on***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 40 of 403 agriculture and forestry in the next few decades, the body of evidence points towards increasing risks of net adverse impacts on U.S. food production, agriculture and forest productivity as temperatures continue to rise. These impacts are global and may exacerbate problems outside the U.S. that raise humanitarian, trade, and national security issues for the U.S. 3. The science upon which the Agency relies The EPA received comments in response to the April 2012 proposed NSPS rule (77 FR 22392) that addressed the scientific underpinnings of the EPA’s 2009 Endangerment Finding and hence the proposed rule. The EPA carefully reviewed all of those comments. It is important to place these comments in the context of the history and associated voluminous record on this subject that has been compiled over the last few years, including: 1) the process by which the Administrator reached the Endangerment Finding in 2009; 2) the EPA’s response in 2010 to ten administrative petitions for reconsideration of the Endangerment Finding (the Reconsideration Denial) 8 ; and 3) the decision by the United States Court of Appeals for the District of Columbia

8 “EPA’s Denial of the Petitions to Reconsider the Endangerment and Cause or Contribute Findings for Greenhouse Gases Under Section 202(a) of the Clean Air Act, 75 Fed. Reg. 49,557 (Aug. 13, 2010) (“Reconsideration Denial”).***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 41 of 403 Circuit (the D.C. Circuit or the Court) in 2012 to uphold the Endangerment Finding and the Reconsideration Denial. 9,10 As outlined in Section VIII.A. of the 2009 Endangerment Finding, the EPA’s approach to providing the technical and scientific information to inform the Administrator’s judgment regarding the question of whether GHGs endanger public health and welfare was to rely primarily upon the recent, major assessments by the U.S. Global Change Research Program (USGCRP), the Intergovernmental Panel on Climate Change (IPCC), and the National Research Council (NRC) of the National Academies. These

assessments addressed the scientific issues that the EPA was required to examine, were comprehensive in their coverage of the GHG and climate change issues, and underwent rigorous and exacting peer review by the expert community, as well as rigorous levels of U.S. government review. The EPA received thousands of comments on the proposed Endangerment Finding and responded to them in depth in an 11-volume Response to Comments (RTC) document. 11 While the EPA gave careful consideration to all

9 Coalition for Responsible Regulation, Inc. v. EPA , 684 F.3d 102 (D.C. Cir. 2012), rehearing and rehearing en banc den.

________ (“ CRR ”). 10 We discuss litigation history involving this rulemaking in more detail later in this section.

11 “Endangerment and Cause or Contribute Findings for Greenhouse Gases under Section 202(a) of the Clean Air Act: EPA's Response***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 42 of 403 of the scientific and technical information received, the agency placed less weight on the much smaller number of individual studies that were not considered or reflected in the major assessments; often these studies were published after the submission deadline for those larger assessments. Primary reliance on the major scientific assessments provided the EPA greater assurance that it was basing its judgment on the best available, well-vetted science that reflected the consensus of the climate science community. The EPA reviewed individual studies not incorporated in the assessment literature largely to see if they would lead the EPA to change its interpretation of, or place less weight on, the major findings reflected in the assessment reports. From its review of individual studies submitted by commenters, the EPA concluded that these studies did not change the various conclusions and judgments the EPA drew from the more comprehensive assessment reports. The major findings of the USGCRP, IPCC, and NRC assessments supported the EPA’s determination that GHGs threaten the public health and welfare of current and future generations. The EPA presented this scientific support at length in the Endangerment Finding,

to Public Comments,” http://www.epa.gov/climatechange/endangerment/#comments (“Response to Comments” or “RTC”).***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 43 of 403 in its Technical Support Document (which summarized the findings of USGCRP, IPCC and NRC) 12 and in the RTC. The EPA then reviewed ten administrative petitions for reconsideration of the Endangerment Finding in 2010. In the Reconsideration Denial, the Administrator denied those petitions on the basis that the Petitioners failed to provide substantial support for the argument that the EPA should revise the Endangerment Finding and therefore their objections were not of “central relevance” to the Finding. The EPA prepared an accompanying three-volume Response to Petitions (RTP) document to provide additional information, often more technical in nature, in response to the arguments, claims, and assertions by the petitioners to reconsider the Endangerment Finding. 13 The 2009 Endangerment Finding and the 2010 Reconsideration Denial were challenged in a lawsuit before the D.C. Circuit. On June 26, 2012, the Court upheld the Endangerment Finding and the Reconsideration Denial, ruling that the Finding (including the Reconsideration Denial) was not arbitrary or capricious, was consistent with the U.S. Supreme Court’s decision in

12 “Technical Support Document for Endangerment and Cause or Contribute findings for Greenhouse Gases under Section 202(s) of the Clean Air Act (Dec. 7, 2009), http://www.epa.gov/climatechange/Downloads/endangerment/Endanger ment_TSD.pdf (TSD). 13 http://www.epa.gov/climatechange/endangerment/petitions.html***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 44 of 403 Massachusetts v. EPA, which granted to the EPA the authority to regulate GHGs, 14 and was adequately supported by the

administrative record. 15 The Court found that the EPA had based

its decision on “substantial scientific evidence” and noted that

the EPA’s reliance on assessments was consistent with the

methods decision-makers often use to make a science-based judgment. 16 The Court also agreed with the EPA that the Petitioners had “not provided substantial support for their argument that the Endangerment Finding should be revised.” 17 Moreover, the Court supported the EPA’s reliance on the major scientific assessment reports conducted by USGCRP, IPCC, and NRC

and found that: The EPA evaluated the processes used to develop the various assessment reports, reviewed their contents, and considered the depth of the scientific consensus the reports represented. Based on these evaluations, the EPA determined the assessments represented the best source material to use in deciding whether GHG emissions may be reasonably anticipated to endanger public health or welfare. 18

As the Court stated –

It makes no difference that much of the scientific evidence in large part consisted of ‘syntheses’ of individual studies and research. Even

14 549 U.S. 497 (2007). 15 CRR , 684 F.3d at 117-27. 16 Id. at 121. 17 Id. at 125. 18 Id. at 120.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 45 of 403 individual studies and research papers often synthesize past work in an area and then build upon it. This is how science works. The EPA is not required to re-prove the existence of the atom every time it approaches a scientific question. 19

In the context of this extensive record and the recent affirmation of the Endangerment Finding by the Court, the EPA considered all of the submitted comments and reports for the April 2012 proposed NSPS rule. As it did in the Endangerment Finding, the EPA gave careful consideration to all of the

scientific and technical comments and information in the record. The major peer-reviewed scientific assessments, however, continue to be the primary scientific and technical basis for the Administrator’s judgment regarding the threats to public health and welfare posed by GHGs. Commenters submitted two major peer-reviewed scientific assessments released after the administrative record concerning the Endangerment Finding closed after the EPA’s 2010 Reconsideration Denial: the IPCC’s 2012 “Special Report on Managing the Risks of Extreme Events and Disasters to Advance Climate Change Adaptation” (SREX) and the NRC’s 2011 “Report on Climate Stabilization Targets: Emissions, Concentrations, and

19 Id. at 120.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 46 of 403 Impacts over Decades to Millennia” (Climate Stabilization Targets). According to the IPCC in the SREX, “A changing climate leads to changes in the frequency, intensity, spatial extent, duration, and timing of extreme weather and climate events, and can result in unprecedented extreme weather and climate

events. 20 ” The SREX documents observational evidence of changes in some weather and climate extremes that have occurred globally since 1950. The assessment also provides evidence regarding the cause of some of these changes to elevated concentrations of GHGs, including warming of extreme daily temperatures, intensified extreme precipitation events, and increases in extreme coastal high water levels due to rising sea level. The SREX projects further increases in some extreme weather and climate events during the 21st century. Combined with increasing vulnerability and exposure of populations and assets, changes in extreme weather and climate events have consequences for disaster risk, with particular impacts on the water, agriculture and food security and health sectors. In the Climate Stabilization Targets assessment, the NRC

states:

20 SREX, p. 7.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 47 of 403 Emissions of carbon dioxide from the burning of fossil fuels have ushered in a new epoch where human activities will largely determine the evolution of Earth’s climate. Because carbon dioxide in the atmosphere is long lived, it can effectively lock Earth and future generations into a range of impacts, some of which could become very severe. 21

The assessment concludes that carbon dioxide emissions will alter the atmosphere’s composition and therefore the climate for thousands of years; and attempts to quantify the results of stabilizing GHG concentrations at different levels. The report also projects the occurrence of several specific climate change impacts, finding warming could lead to increases in heavy rainfall and decreases in crop yields and Arctic sea ice extent, along with other significant changes in precipitation and stream flow. For an increase in global average temperature of 1 to 2 oC above pre-industrial levels, the assessment found that the area burnt by wildfires in western North America will likely more than double and coral bleaching and erosion will increase due both to warming and ocean acidification. An increase of 3 oC will lead to a sea level rise of 0.5 to 1 meter by 2100. With an increase of 4 oC, the average summer in the United States would be as warm as the warmest summers of the past century. The assessment notes that although many important aspects of climate

21 Climate Stabilization Targets, p. 3.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 48 of 403 change are difficult to quantify, the risk of adverse impacts is likely to increase with increasing temperature, and the risk of surprises can be expected to increase with the duration and magnitude of the warming. Several other National Academy assessments regarding climate have also been released recently. The EPA has reviewed these assessments and finds that in general, the improved understanding of the climate system they and the two assessments described above present strengthens the case that GHGs are endangering public health and welfare. Three of the new NRC assessments provide estimates of projected global sea level rise that are twice as large or more than the rise estimated in a 2007 IPCC assessment of between 0.18 and 0.59 meters by the end of the century, relative to 1990 (and noting that including poorly understood ice sheet processes would likely increase those projections). 22 While these three NRC assessments continue to recognize and characterize the uncertainty inherent in accounting for ice sheet processes, these revised estimates strongly support and strengthen the existing finding that GHGs are reasonably anticipated to endanger public health and

22 Climate Stabilization Targets; “National Security Implications for U.S. Naval Forces” (2011) (National Security Implications); “Sea Level Rise for the Coasts of California, Oregon, and Washington: Past, Present, and Future” (2012) (Sea Level Rise).***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 49 of 403 welfare. Other key findings of the recent assessments are described briefly below:

One of these assessments projects a global sea level rise of 0.5 to 1.4 meters by 2100, which is sufficient to lead to rising relative sea level even in the northern states. 23 Another assessment considers potential impacts of sea level rise and suggests that “the Department of the Navy should expect roughly 0.4 to 2 meters global average sea-level rise by 2100. 24 This assessment also recommends preparing for increased needs for humanitarian aid, responses to climate change in geopolitical hotspots including possible mass migrations and addressing changing security needs in the Arctic as sea ice retreats. A third NRC assessment found that it would be “prudent for security analysts to expect climate surprises in the coming decade . . . and for them to become progressively more serious and more frequent thereafter[.]” 25 Another NRC assessment finds that “the magnitude and rate of the present greenhouse gas increase place the climate system

in what could be one of the most severe increases in radiative

23 Sea Level Rise, p. XX. 24 National Security Implications, p. 9. 25 “Climate and Social Stress: Implications for Security Analysis” (2012), p.3.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 50 of 403 forcing of the global climate system in Earth history.” 26 ) This

assessment finds that CO 2 concentrations by the end of the century will likely exceed levels not present in the 30 million years since the formation of the Antarctic and Greenland Ice

Sheets. 27 The assessment examines evidence from past climatic changes and concludes that the climate could be more sensitive to greenhouse gases, the tropical surface temperatures less well regulated, sea level rise higher, and the oceans more anoxic than current expectations. The report draws potential parallels with non-linear events such as the Paleo-Eocene Thermal Maximum, a rapid global warming event about 55 million years ago associated with mass extinctions and other disruptions. The assessment notes that acidification and warming caused by GHG increases similar to the changes expected over the next hundred years likely caused up to four of the five major coral reef crises of the past 500 million years. Similarly, another NRC assessment finds that “[t]he chemistry of the ocean is changing at an unprecedented rate and magnitude due to anthropogenic carbon dioxide emissions; the rate of change exceeds any known to have occurred for at least

26 “Understanding Earth’s Deep Past: Lessons for Our Climate Future” (2011), p.138. 27 ??? Comment [A30]: Omit ending parenthesis***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 51 of 403 the past hundreds of thousands of years.” 28 The assessment notes that the full range of consequences is still unknown, but the risks “threaten coral reefs, fisheries, protected species, and other natural resources of value to society” (p. 5). Comments were submitted in support of the Endangerment Finding and providing additional documentation showing that climate change is a threat to public health and welfare. Commenters provided several individual studies and documentation of observed or projected climate changes of local importance or concern to commenters. The EPA appreciates these comments, but as previously stated, we place lesser weight on individual studies than on major scientific assessments. Local observed changes must be assessed in the context of the broader scientific picture, as it is more difficult to draw robust conclusions regarding climate change over short time scales and in small geographic regions. The EPA plans to continue relying on the major assessments by the USGCRP, the IPCC, and the NRC. Studies from these bodies

address the scientific issues that the Administrator must examine, they represent the current state of knowledge on the key elements for the endangerment analysis, comprehensively

28 “Ocean Acidification: A National Strategy to Meet the Challenges of a Changing Ocean” (2010), p. 5.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 52 of 403 cover and synthesize thousands of individual studies to obtain the majority conclusions from the body of scientific literature and undergo a rigorous and exacting standard of review by the peer expert community and U.S. government. Several commenters argued that the Endangerment Finding

should be reconsidered or overturned based on those commenters’ reviews of specific climate science literature, including publications that have appeared since the EPA’s 2010 Reconsideration Denial. Some commenters presented their own compilations of individual studies and other documents to support their assertions that climate change will have beneficial effects in many cases and that climate impacts will

not be as severe or adverse as the EPA and a certain USGCRP 2009 report have stated. Some commenters also concluded that U.S. society will easily adapt to climate change and that it therefore does not threaten public health and welfare, and some commenters questioned the Endangerment Finding based on a 2011 EPA Inspector General’s report.

The EPA reviewed the submitted information and found that overall, the EPA had addressed the commenters’ critiques of the

rule’s scientific basis were addressed in the EPA’s response to comments for the 2009 Endangerment Finding, the EPA’s responses in the 2010 Reconsideration Denial, or the D.C. Circuit Circuit’s***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 53 of 403

in its 2012 decision to uphold upholding the EPA’s 2009 Endangerment Finding. The EPA nonetheless carefully reviewed these comments and associated documents and found that nothing in them would change the conclusions and that the EPA reached in the Endangerment Finding. These recent publications submitted by commenters, and any new issues that are extracted from them, do not undermine either the significant body of scientific evidence that has accumulated over the years or the conclusions presented in the substantial peer-reviewed assessments of the USGCRP, NRC,

and IPCC. One commenter submitted e-mails between climate change researchers from the period 1999 to 2009 that were surreptitiously obtained from a University of East Anglia server in 2009 and publicly released in 2011. According to the commenter, these e-mails showed that the climatologists distorted their research results to prove that climate change

causes adverse effects. The EPA reviewed these emails and found that they raised no issues that Petitioners had not already raised concerning other emails from the same incident, released in 2009. The commenter’s unsubstantiated assumptions and subjective assertions regarding what the e-mails purport to show about the state of climate change science is not adequate***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 54 of 403 evidence to challenge the voluminous and well-documented body of science that underpins the Administrator’s Endangerment Finding. Some commenters argued for reconsideration based on uncertainty regarding climate science. However, the EPA made the decision to find endangerment with full and explicit recognition of the uncertainty involved, stating that “[t]he Administrator acknowledges that some aspects of climate change science and the projected impacts are more certain than others.” 29 . The D.C. Circuit subsequently noted that “the existence of some uncertainty does not, without more, warrant invalidation of an endangerment finding.” 30 Some commenters also argued that the U.S. will adapt to climate change impacts and that therefore climate change impacts pose no threat. However, the D.C. Circuit, in CRR , held that considerations of adaption are irrelevant to the Endangerment determination. The Court stated, “These contentions are foreclosed by the language of the statute and the Supreme

Court's decision in Massachusetts v. EPA ” because “predicting society’s adaptive response to the dangers or harms caused by

29 74 FR 66524. 30 CRR , 684 F.3d at 121. Comment [A31]: Please check citations to this case; although abbreviated here, it is fully spelled out in later footnotes 89 and 97.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 55 of 403 climate change” does not inform the “scientific judgment” that the EPA is required to make regarding an Endangerment Finding. 31 Some commenters raised issues regarding the EPA Inspector General’s report, Procedural Review of EPA’s Greenhouse Gases Endangerment Finding Data Quality Processes

. 32 These commenters mischaracterized the report’s scope and conclusions and thus overstate the significance of the Inspector General’s procedural recommendations. Nothing in the Inspector General’s report questions the scientific validity of the Endangerment Finding, because that report did not evaluate the scientific basis of the Endangerment Finding. Rather, the Inspector General offers recommendations for clarifying and standardizing internal procedures for documenting data quality and peer review processes when referencing existing peer reviewed science in EPA

actions. 33

31 Id. at 117. The EPA took a similar position in the Endangerment Finding, in which we responded to similar comments regarding society’s ability to adapt to climate change by stating: “Risk reduction through adaptation and GHG mitigation measures is of course a strong focal area of scientists and policy makers, including the EPA; however, the EPA considers adaptation and mitigation to be potential responses to endangerment, and as such has determined that they are outside the scope of the endangerment analysis.” 74 FR 66512. 32 Report No. 11-P-0702 (September 26, 2011). 33 Unrelated to the Endangerment Finding and its validation by the Court, the EPA has made progress towards implementing the OIG recommendations. Comment [A32]: Spell out OIG in FN.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 56 of 403 In addition, some commenters argued that the Endangerment Finding should be overturned because of the carbon dioxide fertilization effect, that is, the proposition that increased amounts of carbon dioxide can spur growth of vegetation. However, these commenters did not show how the science they provide on the subject differs from the carbon dioxide fertilization science already considered by the Administrator in the Endangerment Finding or how the existence of some benefits from the carbon dioxide fertilization effect could outweigh the numerous negative impacts of climate change. In sum, the EPA reviewed all of the comments purporting to refute the Endangerment Finding to determine whether they provide evidence that the Administrator’s judgment that climate change endangers public health and welfare was flawed, either because the Administrator misinterpreted the underlying assessments, because the science in new peer reviewed assessments differs from that in previous assessments, or because new individual studies provide compelling reasons for the EPA to change its interpretation of, or place less weight on, the major findings reflected in the assessment reports. In all cases, the commenters failed to demonstrate that the science

that the Administrator relied on was inaccurate or that the science is of central relevance to the Administrator’s judgment***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 57 of 403 regarding endangerment. 34 For these reasons, the commenters on the original proposal that criticized the Endangerment Finding have not provided a sufficient basis to cast doubt on the Finding.

B. GHG emissions from fossil fuel-fired EGUs Fossil fuel-fired electric utility generating units are by far the largest emitters of GHGs, primarily in the form of CO 2 ,among stationary sources in the U.S., and among fossil fuelfired units, coal-fired units are by far the largest emitters. This section describes the amounts of those emissions and places those amounts in the context of the national inventory of GHGs. The EPA prepares the official U.S. Inventory of Greenhouse

Gas Emissions and Sinks 35 (the U.S. GHG Inventory) to comply with

commitments under the United Nations Framework Convention on Climate Change (UNFCCC). This inventory, which includes recent trends, is organized by industrial sectors. It provides the information in Table 2 below, which presents total U.S.

34 The EPA notes that commenters have previously submitted voluminous reviews of climate science as a part of their comments on rules. While the EPA will continue to consider the entirety of all submissions, the EPA’s responses will be primarily based on the comment itself. 35 “Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990 – 2011”, Report EPA 430-R-13-001, United States Environmental Protection Agency, April 15, 2013.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 58 of 403 anthropogenic emissions and sinks of GHGs, including CO 2 emissions, for the years 1990, 2005 and 2011. 36 **Table 2. U.S. GHG Emissions and Sinks by Sector (teragram carbon dioxide equivalent (Tg CO**  **2 Eq.))**  **37**

**SECTOR 1990 2005 2011**

Energy 5,267.3 6,251.6 5,745.7

Industrial Processes 316.1 330.8 326.5

Solvent and Other Product Use 4.4 4.4 4.4 Agriculture 413.9 446.2 461.5 Land Use, Land-Use Change and Forestry 13.7 25.4 36.6

Waste 167.8 136.9 127.7

Total Emissions 6,183.3 7 ,195.3 6 ,702.3 Land Use, Land-Use Change and Forestry (Sinks) (794.5) (997.8) (905.0) Net Emissions (Sources and Sinks) 5,388.7 6,197.4 5,797.3

Total fossil energy-related CO 2 emissions (including both stationary and mobile sources) are the largest contributor to total U.S. GHG emissions, representing 78.7 percent of total

36 Sinks are a physical unit or process that stores GHGs, such as forests or underground or deep sea reservoirs of carbon dioxide. 37 From Table 2-3 of “Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990 – 2011”, April 15, 2013, EPA 430-R-13-001.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 59 of 403 2011 GHG emissions. In 2011, fossil fuel combustion by the electric power sector –-entities that burn fossil fuel and whose primary business is the generation of electricity –- accounted for 39.6 percent of all energy-related CO 2 emissions. Table 3 below presents total CO 2 emissions from fossil fuel-fired EGUs, for years 1990, 2005 and 2011. 38

**Table 3. U.S. GHG Emissions from Generation of Electricity from Combustion of Fossil Fuels (Tg CO**  **2 Eq.)** 

38 Note that for the purposes of reporting national GHG emissions under the UNFCCC, the U.S. GHG Inventory is calculated using internationally accepted methodological guidance from the Intergovernmental Panel on Climate Change (IPCC). In accordance with IPCC guidance, CO 2 emissions from combustion of biogenic feedstocks are not reported in the energy sector, but are instead reported separately as a "Memo item" in the U.S. GHG Inventory. Consistent with the IPCC guidance, any carbon stock changes related to the use of biogenic feedstocks in the energy sector, and the CO 2 emissions associated with those carbon stock changes, are accounted for under the forestry and/or agricultural sectors of the U.S. GHG Inventory. Attribution of CO 2 emissions from the combustion of biogenic feedstocks by stationary sources in the energy sector to the forestry and/or agricultural sectors, in the context of U.S. GHG emissions reporting to the UNFCCC, should not be interpreted as an indication that such emissions are “carbon neutral.” **GHG EMISSIONS 1990 2005 2011**

Total CO 2 from fossil fuel combustion EGUs 1,820.8 2 ,402.1 2 ,158.5

- from coal 1,547.6 1,983.8 1,722.7 - from natural gas 175.3 318.8 408.8 - from petroleum 97.5 99.2 26.6***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 60 of 403

We are aware that nitrous oxide (N 2 O) and, to a lesser extent, methane (CH 4 ) may be emitted from fossil fuel-fired EGUs, especially from coal-fired circulating fluidized bed (CFB) combustors and from units with selective catalytic reduction (SCR) and selective non-catalytic reduction (SNCR) systems

installed for NO X control. The estimated emissions for N 2 O and

CH 4 from fossil fuel-fired EGUs are about 17.9 and 0.4 Tg of CO 2 equivalent in 2011, respectively, which is about 0.8 percent of

total CO 2 equivalent emissions from fossil fuel-fired electric power generating units. However, we are not proposing separate

N 2 O or CH 4 emission limits or an equivalent CO 2 emission limit in today’s notice because we lack more precise data on the quantity

of these emissions and information on cost-effective controls. We request comment on this approach and we solicit information about the quantity of N 2 O and CH 4 emissions from these affected sources and possible controls. C. The utility power sector and how its structure is changing 1. Utility power sector. The majority of power in the U.S. is generated from the combustion of coal, natural gas and other fossil fuels. Natural gas-fired EGUs typically use one of two technologies. Natural gas combined cycle (NGCC) units first generate power***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 61 of 403 from a combustion turbine (the combustion cycle). The unused

heat from the combustion turbine is then routed to a Heat Recovery Steam Generator (HRSG) which generates steam which is used to generate power using a steam turbine (the steam cycle). The combining of these generation cycles increases the overall efficiency of the system. Simple cycle combustion turbines only use a single combustion turbine to produce electricity (i.e., there is no heat recovery). The power output from these simple cycle combustion turbines can be easily ramped up and down making them ideal for “peaking” operations. Coal-fired utility boilers are primarily either pulverized coal (PC) boilers or fluidized bed (FB) boilers. At a PC boiler, the coal is crushed (pulverized) into a powder in order to increase its surface area. The coal powder is then blown into a boiler and burned. In a coal-fired boiler using fluidized bed combustion, the coal is burned in a layer of heated particles suspended in flowing air. Power can also be generated using gasification technology. An integrated gasification combined cycle (IGCC) unit gasifies coal to form a syngas composed of carbon monoxide (CO) and hydrogen (H 2 ), which can be combusted in a combined cycle system

to generate power.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 62 of 403 2. Changing structure of the power sector a. Technological developments and costs Since the April 2012 proposal, a few coal-fired units have reached the advanced stages of construction and development, which suggests that setting a separate standard for new fossil fuel-fired boilers and IGCC units is appropriate. Progress on Southern Company's Kemper County Energy Facility, which will deploy IGCC with partial CCS, has continued, and the project is now over 75% complete. Additionally, two other projects, Summit Power's Texas Clean Energy Project (TCEP) and the Hydrogen Energy California Project (HECA) – both of which will deploy IGCC with CCS – continue to move forward. The EIA modeling projects that coal-fired power generation will remain the single largest portion of the electricity sector beyond 2030. The EIA modeling also projects that few, if any, new coal-fired EGUs

would be built in this decade and that those that are built

would have CCS. 39 Continued progress on these projects is consistent with the EIA modeling that suggests that a small number of coal-fired power plants may be constructed. The primary reasons for this rate of current and projected future

39 Even in its sensitivity analysis, EIA does not project any additional coal beyond its reference case until 2023, in a case where power companies assume no GHGs emission limitations, and until 2025 in any sensitivity analysis in which which that assumes GHGs emission limitations.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 63 of 403 development of new coal projects include highly competitive natural gas prices, lower electricity demand, and increases in the supply of renewable energy. Natural gas prices have decreased dramatically and generally stabilized in recent years, as new drilling techniques have brought additional supply to the marketplace and greatly increased the domestic resource base. As a result, natural gas prices are expected to be competitive for the foreseeable future, and EIA modeling and utility announcements confirm that utilities are likely to rely heavily on natural gas to meet new demand for electricity generation. On average, as discussed below, the cost of generation from a new natural-gas fired power plant (a natural gas combined cycle (NGCC) unit) is expected to be significantly lower than the cost of generation from a new coal-fired power plant. 40 Other drivers that may influence decisions to build new power plants are increases in renewable energy supplies, often due to state and federal energy policies. Many states have adopted renewable portfolio standards (RPS), which require a certain portion of electricity to come from renewable energy sources such as solar or wind. The federal government has also

40 Levelized Cost of New Generation in the Annual Energy Outlook 2011 http://205.254.135.24/oiaf/aeo/electricity_generation.html. Comment [A33]: EPA regulations, such as MATS, are not also a factor?

Comment [A34]: The weblink provided in the footnote does not appear to work. Please provide a publicly accessible link to the report.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 64 of 403 adopted incentives for electric generation from renewable energy sources and loan guarantees for new nuclear power plants. Due to these factors, the EIA projections from the last several years show that natural gas is likely to be the most widely-used fossil fuel for new construction of electric generating capacity through 2020, along with renewable energy, nuclear power, and a limited amount of coal with CCS.

b. Energy sector modeling Various energy sector modeling efforts, including projections from the Energy Information Agency ( EIA ) and the EPA, forecast trends in new power plant construction and utilization of existing power plants that are consistent with the above-described technological developments and costs. The EIA forecasts the structure and developments in the power sector in its annual report, the Annual Energy Outlook (AEO). These reports are based on economic modeling and that reflects existing policy and regulations, such as state RPS programs and

federal tax credits for renewables. 41 The current report, AEO 2013, shows that although some coal-fired power plants are currently under construction and expected to begin operation inthe next several years (referred to as “planned”), no new modelprojected (“unplanned”) coal-fired capacity will come online

41 http://www.eia.gov/forecasts/aeo/chapter_legs_regs.cfm. Comment [A35]: Please provide references to the projections.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 65 of 403 after 2012. Instead, according to the AEO 2013, the vastmajority of new generating capacity will be either natural gasfired or renewable, with a very small amount of new coal with CCS that is included in the AEO reference case in response to Federal and State incentives. The EIA projections from the last several years show that natural gas is likely to be the most widely-used fossil fuel for new construction of electric generating capacity through 2020. 42 However, coal will remain an important part of the fuel mix for power generation, particularly for existing sources. Modeling from both the Energy Information Administration ( EIA ) and the EPA predict that coalfired generation will remain the largest single source of electricity in the U.S. through 2040. In the EIA’s AEO 2013, 43 coal will supply 39 percent of all electricity in both 2020 and

2025. The AEO 2013 projects the need for 25.9 GW of additional baseload or intermediate load generation capacity by 2020 (this includes projects that are under development (i.e., being constructed or in advance planning) and model-projected nuclear, coal, and NGCC projects). The vast majority of this new electric

42 Annual Energy Outlook 2010, 2011, 2012, and 2013. 43 Energy Information Administration’sAdminstration’s Annual Energy Outlook for 2013, Final Release available at http://www.eia.gov/forecasts/aeo/index.cfm

.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 66 of 403 capacity (22.5 GW) is already under development (under construction or in advanced planning); it includes about 6.1 GW of new coal-fired capacity, 5.5 GW of new nuclear capacity, and 10.9 GW of new NGCC capacity. The EPA believes that most current fossil fuel-fired projects are already designed to meet limits consistent with today’s proposal (or they have already commenced construction and are thus not impacted by today’s notice). The AEO 2013 also projects an additional 3.4 GW of new baseload capacity additions, which are model-projected (unplanned). This consists of 3.1 GW of new NGCC capacity, and 0.3 GW of new coal equipped with CCS (incentivized with some government funding). Therefore, the AEO 2013 projections suggests that this proposal would only impact small amounts of new power generating capacity through 2020, all of which is expected to already meet the proposed emissions standards without incurring further control costs. In AEO 2013, this is also true through 2030, where new model-projected (unplanned) intermediate and baseload capacity is expected to be compliant with the proposed standard without incurring further control costs (48.2 GW of NGCC and 0.3 GW of coal with CCS, cumulative). The EPA modeling using the Integrated Planning Model (IPM), a detailed power sector model that the EPA uses to support power sector regulations, also shows limited future construction of***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 67 of 403 new coal-fired power plants under the base case. 44 The EPA’s projections from IPM can be found in the RIA. c. Integrated Resource Plans The trends in the power sector described above are also apparent in many power companies’ publicly available long-term resource plans – termed Integrated Resource Plans (IRPs) - of many power companies. The EPA has reviewed publicly available IRPs from a range of companies (e.g., varying in size, location, current fuel mix), and these plans are generally consistent with both EIA and EPA modeling projections. Companies seem focused on demand-side management programs to lower future electricity demand and mostly reliant on a mix of new natural gas-fired generation and renewable energy to meet increased load demand and to replace retired generation capacity. Notwithstanding this clear trend towards natural gas-fired generation and renewables, many of the IRPs raise fuel diversity concerns and include options to diversify new generation capacity beyond natural gas and renewable energy. Several IRPs indicate that companies are considering new nuclear generation, including either traditional nuclear power plants or small modular reactors, and new coal-fired generation capacity with and without CCS technology. Based on these IRPs, the EPA acknowledges that a small

44 http://www.epa.gov/airmarkets/progsregs/epaipm/BaseCasev410.html#documentation. Comment [A36]: Please add a reference for this block quote. Has EPA considered referencing the Minnesota PUC’s recent decision on Great River Energy’s resource plan?***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 68 of 403 number of new fossil fuel-fired power plants may be built in the future. While this is contrary to the economic modeling predictions, the Agency understands that economic modeling may not fully reflect the range of factors that a particular company may consider when evaluating new generation options, such as fuel diversification. By the same token, as discussed below, it is possible that some of this potential new coal-fired construction may occur because developers are able to design projects that can provide competitively priced electricity for a specific geographic region. D. Statutory background Section 111 of the Clean Air Act (the Standards of Performance for New Sources or NSPS program) establishes mechanisms for regulating emissions of air pollutants from stationary sources that are key in this rulemaking. As a preliminary step to regulation, the EPA must list categories of stationary sources that the Administrator, in his or her judgment, finds to “cause[], or contribute[] significantly to, air pollution which may reasonably be anticipated to endanger public health or welfare.” 45

45 CAA, §111(b)(1)(A). The EPA has made endangerment findings under this section for more than 60 stationary source categories and subcategories that are now subject to CAA section 111. Comment [A37]: EPA previously made endangerment findings for Subpart Da and KKKK sources when they were originally listed. citations to those should be added in this FN.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 69 of 403 Once the EPA has listed a source category, the EPA proposes and then promulgates “standards of performance” for “new sources” in the category. 46 “New source” include sources that “commence[]” either “construction” or “modification” after the date of the proposal. 47 A modification is “any physical change ... or change in the method of operation ... which increases the amount of any air pollutant emitted by such source or which results in the emission of any air pollutant not previously emitted,” unless it is a specific type of change, exempt from consideration as a modification, such as installation of pollution control projects. 48 An existing facility is also considered a new source if it undertakes a “reconstruction,” which is the replacement of components to such an extent that the capital costs of the new equipment or components exceed 50 percent of what is believed to be the cost of a completely new facility. 49 In establishing standards of performance, the EPA has significant discretion to create subcategories based on source type, class or size. 50

46 CAA, §111 (b)(1)(B). 47 CAA, §111(a)(2). 48 CAA, §111(a)(4); 40 CFR 60.2, 60.14(e). 49 40 CFR 60.15. 50 CAA, §111(b)(2).***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 70 of 403 Clean Air Act section 111(a)(1) defines a “standard of performance” as a standard for emissions of air pollutants which reflects the degree of emission limitation achievable through the application of the best system of emission reduction which (taking into account the cost of achieving such reduction and any nonair quality health and environmental impact and energy requirements) the Administrator determines has been adequately demonstrated.

We call this level of control the best system of emission reduction adequately demonstrated (BSER). 51 The standard that the EPA develops, based on the BSER, is commonly a numericalemissions limit, expressed as a performance level (e.g., a ratebased standard). Generally, the EPA does not prescribe a particular technological system that must be used to comply with a standard of performance. Rather, sources generally can select any combination of measures that will achieve equivalent or greater control of emissions. Regarding other titles in the CAA, this rulemaking has implications for EGUs and other stationary sources in the CAA PSD program under Title I, part C, and the operating permits program under Title V. We discuss these implications in section

51 We may occasionally refer to this level of control as the “best demonstrated system.” In the past, this level of control was frequently referred to as the “best demonstrated technology” (BDT). Comment [A38]: Has EPA considered adding examples of other NSPS that do prescribe a particular technological system?***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 71 of 403

X. E. Regulatory and litigation background The EPA initially included fossil fuel-fired EGUs (which includes EGUs that burn fossil fuel including coal, gas, oil and petroleum coke and that use different technologies, including boilers and combustion turbines) in a category that it listed under section 111(b)(1)(A), and the EPA promulgated the first set of standards of performance for EGUs in 1971, codified in subpart D. 52 As discussed in Section IV.D., the EPA has revised those regulations, and in some instances, revised the subparts, several times over the ensuing decades. None of these rulemakings or codifications, however, have constituted a new listing under CAA §111(b)(1)(A). In 1979, the EPA revised subpart D; as part of this revision, the EPA formed subpart Da and promulgated NSPS for electric utility steam generating units. 53 These NSPS on June 11, 1979 apply to units capable of firing more than 73 megawatts (MW) (250 MMBtu/h) heat input of fossil fuel that commenced construction, reconstruction, or modification after September

52 “Standards of Performance for Fossil-Fuel-Fired Steam Generators for Which Construction Is Commenced After August 17, 1971,” 36 Fed. Reg. 24875 (Dec. 23, 1971) codified at 40 CFR 60.40-46; 36 Fed. Reg. 5931 (Mar. 31, 1971). 53 “Standards of Performance for Electric Utility Steam Generating Units for Which Construction is Commenced After September 18, 1978 ,” 44 Fed. Reg. 33580 (June 11, 1979)***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 72 of 40318, 1978. The NSPS for EGUs also apply to industrial-commercialinstitutional cogeneration units that sell more than 25 MW and more than one-third of their potential output capacity to any utility power distribution system. The EPA promulgated the most recent significant amendments to subpart Da in 2006, resulting in new criteria pollutant limitations for EGUs (the 2006 Final Rule). 54,55 The 2006 Final Rule did not establish standards of performance for GHG emissions. Two groups of petitioners – 13 governmental entities and three environmental groups – filed petitions for judicial review of this rule by the D.C. Circuit. 56 These petitioners

54 ”Standards of Performance for Electric Utility Steam Generating Units, Industrial-Commercial-Institutional Steam Generating Units, and Small Industrial-Commercial-Institutional Steam Generating Units,” 71 Fed. Reg. 9866 (Feb. 27, 2006). 55 The EPA has regulated emissions of conventional toxic air pollutants from power plants in numerous rulemakings, most recently in the Mercury and Air Toxics rule (“MATS”), “Reconsideration of Certain New Source Issues: National Emission Standards for Hazardous Air Pollutants From Coal- and Oil-Fired Electric Utility Steam Generating Units and Standards ofPerformance for Fossil-Fuel-Fired Electric Utility, IndustrialCommercial-Institutional, and Small Industrial-CommercialInstitutional Steam Generating Units,” 78 Fed. Reg. 24073 (April 24, 2013).

56 State of New York, et al. v. EPA, No. 06–1322 **.** The two groups of petitioners were (1) the States of New York, California, Connecticut, Delaware, Maine, New Mexico, Oregon, Rhode Island, Vermont and Washington; the Commonwealth of Massachusetts; the District of Columbia and the City of New York (collectively ‘‘State Petitioners’’); and (2) Natural Resources Defense Council (NRDC), Sierra Club, and Environmental Defense Fund (EDF)(collectively ‘‘Environmental Petitioners’’).***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 73 of 403 contended, among other issues , that the rule was required to include standards of performance for GHG emissions from EGUs. The Court severed portions of the petitions for review of the 2006 Final Rule that related to GHG emissions. Following the U.S. Supreme Court’s 2007 decision in Massachusetts v. EPA , which gave authority to the EPA to regulate GHGs, the D.C. Circuit remanded the 2006 Final Rule to the EPA upon its own

motion for further consideration of the issues related to GHG emissions in light of Massachusetts. The EPA did not act on that remand. Rather, these certain petitioners and the EPA negotiated a proposed settlement agreement that set deadlines for the EPA to propose and take final action on (1) a rule under CAA section 111(b) that includes standards of performance for GHGs for new and modified EGUs that are subject to 40 CFR part 60, subpart Da; and (2) a rule under CAA section 111(d) that includes emission guidelines for GHGs from existing EGUs that would have been subject to 40 CFR part 60, subpart Da if they were new sources. Pursuant to CAA section 113(g), the EPA provided for a notice-and-comment opportunity on the proposed settlement agreement and, after reviewing the comments received, finalized the agreement. In June 2012, the D.C. Circuit in CRR upheld the EPA’s Endangerment Finding concerning GHGs and the EPA’s companion Comment [A39]: Insert year of settlement agreement?***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 74 of 403 finding that GHGs from motor vehicles contribute to the air pollution that endangers public health and welfare. 57 The Court also upheld standards for motor vehicles that limited GHG

emissions. 58 In addition, the Court affirmed the EPA’s view that stationary source permitting requirements of the Clean Air Act are automatically applicable to a pollutant when that pollutant is regulated under any part of the Act. The Court also dismissed challenges to what we refer to as the Timing Decision 59 and the Tailoring Rule, 60 the EPA’s common sense approach to phasing in GHG permitting requirements to avoid an initial increase in the number of PSD and title V permit applications that would overwhelm the permitting authorities’ administrative capacities. In June 2012, industry entities filed petitions for review of the original proposal for this rulemaking action in the D.C.

Circuit. 61 In December 2012, the D.C. Circuit dismissed these petitions on grounds that the challenged proposed rule is not

57 CRR , 684 F.3d 102; "Endangerment and Cause or Contribute Findings for Greenhouse Gases Under Section 202(a) of the Clean Air Act." 74 FR 66496 (December 15, 2009). 58 "Light-Duty Vehicle Greenhouse Gas Emission Standards and Corporate Average Fuel Economy Standards; Final Rule." 75 FR 25324 (May 7, 2010). 59 "Interpretation of Regulations that Determine Pollutants Covered by Clean Air Act Permitting Programs." 75 FR 17004 (April 2, 2010). 60 Prevention of Significant Deterioration and Title V Greenhouse Gas Tailoring Rule; Final Rule. 75 FR 31514 (June 3, 2010). 61 Las Brisas Energy Center, LLC v. EPA, No. 12-1248 and consolidated cases.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 75 of 403 final agency action subject to judicial review. F. Coordination with other rulemakings EGUs are the subject of several recent CAA rulemakings. 62 In general, most EPA rulemakings affecting the power sector focus on existing sources. Therefore, few interactions are likely between other power sector rules and this rule, which focuses only on new sources. We note that the EPA recently finalized revisions to the

MATS rule as related to new sources. 63 The revised MATS new source emission standards and the updated criteria pollutant new source performance standards, coupled with GHG performance standards in this proposed rule, provide a clear regulatory path for new fossil fuel-fired generation. The EPA recognizes that it is important that each of these efforts achieves its intended environmental objectives in a common-sense, cost-effective manner that is consistent with the

62 We discuss other rulemakings solely for background purposes. The effort to coordinate rulemakings is not a defense to a violation of the CAA. Sources cannot defer compliance with existing requirements because of other upcoming regulations.

63 “Reconsideration of Certain New Source Issues: National Emission Standards for Hazardous Air Pollutants From Coal- and Oil-Fired Electric Utility Steam Generating Units and Standards of Performance for Fossil-Fuel-Fired Electric Utility,Industrial-Commercial-Institutional, and Small IndustrialCommercial-Institutional Steam Generating Units,” April 24, 2013 (78 FR 24073). Comment [A40]: Don’t most also have requirements for new sources too? This seems to imply that they don’t. Maybe it should say “on existing sources as well as new sources”?

Comment [A41]: It is odd to refer to this as a path. Suggest revising to say structure.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 76 of 403 underlying statutory requirements and that minimize impacts on electricity rates and assure a reliable power system. Executive Order (EO) 13563 states that ‘‘[i]n developing regulatory actions and identifying appropriate approaches, each agency shall attempt to promote ... coordination, simplification, and harmonization. Each agency shall also seek to identify, as appropriate, means to achieve regulatory goals that are designed to promote innovation.’’ Recent guidance from the Office of Management and Budget’s Office of Information and Regulatory Affairs has emphasized the importance of, where appropriate and feasible, considering cumulative effects and seeking to harmonize rules in terms of both content and timing. We believe that these recent finalized and proposed rules will allow industry to comply with its obligations under these rules as efficiently as possible, by making coordinated investment decisions and, to the greatest extent possible, adopting integrated compliance strategies. G. Stakeholder input The EPA extensively interacted with many different stakeholders regarding climate change, source contributions, and emission reduction opportunities. These stakeholders included industry entities, environmental organizations and many regional, state, and local air quality management agencies, as***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 77 of 403 well as the general public. As part of developing this proposed rule, the EPA held five listening sessions in February and March 2011 to obtain additional information and input from key stakeholders and the public. Each of the five sessions had a particular target audience; these were the electric power industry, environmental and environmental justice organizations, states and Tribes, coalition groups and the petroleum refinery industry. Each session lasted two hours and featured a facilitated roundtable discussion among stakeholder representatives. The EPA asked key stakeholder groups to identify these roundtable participants in advance of the listening sessions. The EPA accepted comments from the public at the end of each session and via the electronic docket system. 64 On May 3, 2012, the EPA announced that it would hold two public hearings on the original proposed rule. The hearings were both held on May 24, 2012, in Washington, D.C. and Chicago, IL. Also on May 3, 2012, the EPA announced an extension of the public comment period for the original proposed rule, until June 25, 2012. The EPA received approximately more than 2.5 million

64 Comments related to the listening sessions submitted via the electronic docket system are available at www.regulations.gov (docket number EPA-HQ-OAR-2011-0090).***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 78 of 403 public comments on the original proposed rule. 65 While the Agency is not preparing a response-to-comments document responding to the comments it received as part of that process, the EPA has taken into consideration those comments, as well as information received in the listening sessions, in developing this new proposal. **III. Proposed Requirements for New Sources** This section describes the proposed requirements in this rulemaking for new sources. Our rationale for these proposed requirements is provided in Sections IV-X of this preamble.

A. Affected sources We generally refer to sources that would be subject to the standards of performance in this rulemaking variously as “affected” or “covered” sources, units, facilities, or simply as

EGUs. These sources meet both the definition of “affected” and “covered” EGUs subject to an emission standard as provided by this rule, and the requirements for “new” sources as defined under the provisions of CAA section 111. 1. Covered EGUs, generally Subpart Da currently defines an EGU as a boiler that is: 1) capable of combusting more than 250 MMBtu/h heat input of fossil

65 Those comments are available at www.regulations.gov (docket number EPA-HQ-OAR-2011-0660).***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 79 of 403 fuel, 2) that is constructed for the purpose of supplying more than 1/3 of its potential net-electric output capacity to any utility power distribution system for sale, and 3) that isconstructed for the purpose of supplying more than 25 MW netelectric output to any utility power distribution system for sale. We are proposing to define an EGU slightly differently than it is currently defined in subpart Da and in the April 2012 proposal. First, we are proposing to use “supplies 1/3 of their potential electric output to the grid” instead of “constructed for the purpose of supplying more than 1/3 of their potential electric output to the grid” when determining applicability of

the CO 2 standard. This approach to applicability with the CO 2 standard is similar to criteria pollutant emission standards included in both subparts Da and KKKK that vary depending on the fuels combusted. In this case, when EGUs do not supply more than 1/3 of their potential electric output to the grid no CO 2 emissions standard would be applicable. Second, we are proposingto use “more than 219,000 MWh,” as opposed to “25 MW,” netelectrical output to the grid. The proposed change of 25 MW net sales to 219,000 MWh net sales is consistent with the EPA Acid Rain Program (ARP) definition, and we have concluded that it is functionally equivalent to the 25 MW net sales language. The 25 MW sales value has been interpreted to be the continuous sale of***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 80 of 403 25 MW of electricity on an annual basis, which is equivalent to 219,000 MWh. We are also proposing the averaging period for electric sales from an annual basis to a three-year rolling average for stationary combustion turbines. Lengthening this period will ensure that the CO 2 standards only apply to the intended facilities, which are intermediate and baseload EGUs. In addition, we are proposing to add a new applicability criterion that is not currently in subpart Da for the CO 2 standard. Similar to the applicability requirements in the Mercury and Air Toxics Standard, we are proposing that EGUs,

where 10 percent or less of the heat input over a three-year period or which, is derived from a fossil fuel, are not subject to any of the proposed CO 2 standards. For the purposes of this rule, we are proposing several additional changes to the way applicability is currently determined under subpart Da. First, we are proposing a different definition of potential electric output from the current definition in subpart Da. To assure that the applicability does not discourage the installation of the most efficient simple cycle turbines, we are proposing a definition of potential electric output that includes “or the design electric output efficiency on a net output basis” as an alternative to the default 33 percent default efficiency value. Next, we are Comment [A42]: Something is amiss with this sentence. Suggested edits for clarification.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 81 of 403 proposing to add “of the thermal host facility or facilities” to the definition of net-electric output. This would make applicability consistent for both facility-owned CHP and qualifying third-party-owned CHP, since the owner of the CHP does not need to also own the thermal host facility. Finally, consistent with the intent expressed in the NSPS response to comments document of the MATS rule and the April 2012 proposal, we are proposing to amend the definition of a steam generating unit to include “plus any integrated equipment that provides electricity or useful thermal output to either the boiler or to power auxiliary equipment” and delete the existing language “plus any integrated combustion turbines and fuel cells.” We are also proposing to add the additional language to the definition of IGCC and stationary combustion turbine.

2. CO 2 emissions only This action proposes to regulate covered EGU emissions of

CO 2 , and not other constituent gases of the air pollutant GHGs. We identify the pollutant we propose to regulate as GHGs, but, again, only CO 2 emissions are subject to the proposed standard of performance.

3. “New” sources CAA section 111(a)(2) defines a “new source” as “any stationary source, the construction or modification of which is***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 82 of 403 commenced after publication of regulations (or, if earlier, proposed regulations) prescribing a standard of performance under [CAA section 111] which will be applicable to such source.” In contrast, CAA section 111(a)(6) defines an “existing source” as “any stationary source other than a new source.” The definition of a “new source” applies according to its terms for purposes of this rulemaking. Note that we are not proposing standards for new steam generating units and stationary combustion turbines that sell less than 1/3 of their potential output to the grid, new non-natural gas-fired stationary combustion turbines, existing sources undertaking modifications or reconstructions, or certain projects under development as discussed below. As a result, if those types of sources commence construction or modification, they would not be subject to the standards of performance proposed today. 4. Certain projects under development This proposal does not apply to the proposed Wolverine EGU project in Rogers City, Michigan. Based on current information, the Wolverine project appears to be the only fossil fuel-fired boiler or IGCC EGU project presently under development that may be capable of “commencing construction” for NSPS purposes in the very near future and, as currently designed, could not meet the 1,100 lb CO 2 /MWh standard proposed for other new fossil fuelComment [A43]: What is included in this category and what is EPA’s rationale for not including such sources? Do they not fall under the Subpart Da or KKKK categories?***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 83 of 403

fired boiler and IGCC EGUs. The EPA has not formulated a view as to the project’s status in the development process or as to whether the proposed 1,100 lb CO 2 /MWh standard or some other CO 2 standard of performance would be representative of BSER for this project and invites comment on this question. 66 At the time of finalization of this proposal (but not sooner than one year following Federal Register publication of this proposal), if the Wolverine project remains under development and has not either “commenced construction” or been canceled, we anticipate proposing that the project either be made subject to the 1,100

lb CO 2 /MWh standard or be assigned to a subcategory with an

alternate CO 2 standard. Further discussion is provided in the

66 The EPA’s lack of view regarding the appropriate CO 2 standard is closely related to the existence of conflicting information on where the project stands in the development process. The developer has claimed that the project was delayed by issues related to the standards of performance for hazardous air pollutants promulgated in December 2011, 77 FR 9304 (Feb. 16, 2012) (Mercury and Air Toxics Standards, or MATS). Specifically, the developer cited a perceived inability to obtain guarantees from pollution control equipment vendors that the plant would achieve the MATS standards. See Jim Dulzo, As Coal Plant Teeters, Groups Mount Legal Attack , Michigan Land Use Instituteblog, Feb. 13, 2012, http://www.mlui.org/energy/news-views/newsviews-articles/as-coal-plant-teeters-groups-mount-legalattack.html. While some of the MATS new-unit standards were revised upon reconsideration in March 2013, 78 FR 24073 (Apr. 24, 2013), the developer’s claims raise the possibility that the EPA’s own actions may have delayed the project and contributed to the present uncertainty as to the project’s development status.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 84 of 403technical support document in the docket entitled “Fossil FuelFired Boiler and IGCC EGU Projects under Development: Status and Approach.”

There are two other fossil fuel-fired boiler or IGCC EGU projects without CCS – the Washington County project in Georgia and the Holcomb project in Kansas – that appear to remain under development but whose developers have recently represented that the projects have “commenced construction” for NSPS purposes. Based solely on the developers’ representations, the projects would be existing sources, and thus not subject to this proposal. However, neither developer has sought an EPA determination of NSPS applicability; and if upon review it was determined that the projects have not “commenced constructions,” the projects could be situated similarly to the Wolverine project. Accordingly, we propose that if either developer seeks an EPA determination of applicability within 120 days following Federal Register publication of this proposal and the EPA finds that the project has not “commenced construction,” as of the date of the Federal Register publication of this proposal, then that project automatically – without, for example, any supplemental proposal or re-proposal – would be addressed in the***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 85 of 403 same manner as the Wolverine project. 67 Further discussion is provided in the technical support document in the docket

referenced above. 68 We invite comment on all aspects of this approach for addressing the Wolverine project (and the Washington County and Holcomb projects, if applicable). 69

67 In this event, there will not be any proposed standard “which will be applicable to such source” within the meaning of CAA section 111(a)(2), and to the extent that this proposal did, until the time of the applicability determination, apply to that project, this proposal will be considered automatically to be withdrawn as it applies to that project as of the time of the applicability determination. The purpose of this automatic withdrawal is to ensure that the project is placed on the same footing as the Wolverine project as soon as possible. It is worth noting that, if the developers do not seek applicability determinations within the 120 day timeframe , nothing in this rulemaking binds the EPA to the position that the projects have “commenced construction” for NSPS purposes. 68 In the April 2012 GHG NSPS proposal, the Wolverine, Washington County, and Holcomb projects were among a group of 15 projects distinguished from other EGU projects as “potential transitional sources.” This proposal does not continue that distinction. Except as described above for the Wolverine project, and possibly the Washington County and Holcomb projects, any former “potential transitional source” that commences construction after publication of this proposal (and meets any other applicability criteria) will be subject to the final CO 2 standards established in this rulemaking. Any former “potential transitional source” that commenced construction prior to publication of this proposal is an existing source not subject to the CO 2 standards established in this rulemaking, but instead subject to the CO 2 standards that will be be are required to be established for existing sources pursuant to CAA section 111(d). 69 The EPA intends that its treatment of the Wolverine project (and the Washington County and Holcomb projects, if applicable) be severable from its treatment of differently situated sources and considers that severability is logical because of the***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 86 of 403

B. Emission standards In this rulemaking, the EPA is proposing standards of performance (NSPS) for CO 2 emissions from several subcategories of affected sources, which are new fossil fired EGUs described

above in Section III.A. 1. Standards of performance for affected sources The proposed standard of performance for each subcategory is in the form of a gross output-based CO 2 emission limit expressed in units of emissions mass per unit of useful recovered energy, specifically, in pounds per megawatt-hour (lb/MWh). This emission limit would apply to affected sources upon the effective date of the final action. The subcategories, for which the EPA is proposing separate standards of performance, are (1) natural gas-fired stationary combustion turbines with a heat input rating that is greater

than 850 MMBtu/h; 70 (2) natural gas-fired stationary combustion turbines with a heat input rating that is less than or equal to

record-based differences between these sources and differently situated sources and because there is no interdependency in the EPA’s treatment of the different types of sources. This statement concerning severability should not be construed to have implications for whether other components in this rulemaking are severable. 70 This subcategorization of stationary combustion turbines is consistent with the subcategories used in the combustion turbine (subpart KKKK) criteria pollutant NSPS. The size limit of 850 MMBtu/h corresponds to approximately 100 MWe.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 87 of 403 850 MMBtu/h, which are also natural gas fired; and (3) all fossil fuel-fired boilers and IGCC units, which generally are

solid-fuel fired. We are proposing that all affected new fossil fuel-fired EGUs are required to meet an output-based emission rate of a specific mass of CO 2 per MWh of useful output. Specifically, new combustion turbines with a heat input rating greater than 850 MMBtu/h would be required to meet a standard of 1,000 lb CO 2 /MWh. New combustion turbines with a heat input rating less than or equal to 850 MMBtu/h would be required to meet a standard of 1,100 lb CO 2 /MWh. As discussed below, these proposed standards are based on the demonstrated performance of recently constructed natural gas combined cycle (NGCC) units, which are currently in wide use throughout the country, and are currently the predominant fossil fuel-fired technology for new electric generating units in the near future.

New fossil fuel-fired boilers and IGCC units would be required, based on the performance of currently available CCS technology, to meet a standard of 1,100 lb CO 2 /MWh on a 12- operating-month rolling average, or alternatively a lower standard, which we propose as between 950 lb CO 2 /MWh and 1,050 lb

CO 2 /MWh, on a 60-operating-month rolling average as an equivalently stringent standard. The EPA has previously offered***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 88 of 403 sources optional, longer-term emission standards that are discounted from the primary emissions standard in exchange

for combination with the a longer averaging period. We are requesting comment on the appropriate numerical standard such that the 60-operating-month standard would be as stringent as or more stringent than the 12-operating-month standard. We also request comment on an appropriate 12-operating-month standardthat owners/operators electing to comply with the 60-operatingmonth standard would have to comply with. This standard would be numerically between the alternate 12-operating-month standard and an emissions rate of a coal-fired EGU without CCS (e.g., 1,800 lb CO 2 /MWh). This shorter term standard would be more easily enforced and assure adequate emission reductions. While the EPA is proposing specific standards of performance for each subcategory, we are also taking comment on a range of potential emission limitations. We solicit comment on a range of 950 – 1,100 lb CO 2 /MWh for new stationary combustion turbines with a heat input rating greater than 850 MMBtu/h. We also solicit comment on an emission limitation range of 1,000 – 1,150

lb CO 2 /MWh for new stationary combustion turbines with a heat input rating less than or equal to 850 MMBtu/h. In addition, we

solicit comment on an emission limitation for new fossil fuelfired boilers and IGCC units in the range of 1,000 – 1,200 lb Comment [A44]: “in exchange for” sounds like it’s a negotiation.

Comment [A45]: This is unclear. Can EPA be more specific about what goal the shorter term standard would be trying to achieve? To ensure that sources are on track to meet the longer term target?***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 89 of 403

CO 2 /MWh. As discussed below, the proposed method to calculate compliance is to sum the emissions for all operating hours and to divide that value by the sum of the useful energy output over a rolling 12-operating-month period. In the alternative, we solicit comment on requiring calculation of compliance on an annual (calendar year) period. To recognize the environmental benefit of reduced electric transmission and distribution losses of CHP, we are proposing that CHP facilities where at least 20.0 percent of the total gross useful energy output consists of electric or direct mechanical output and 20.0 percent of the total gross useful energy output consists of useful thermal output on a rolling three calendar year basis receive similar credit as currently in subpart Da and the proposed amendments to subpart KKKK (77 FR 52554). Specifically, the measured electric output would be divided by 0.95 to account for a five percent energy loss in the transmission of electricity. The minimal electric and thermal output requirements are to avoid owners/operators from selling trivial amounts of thermal output and claiming a line loss benefit when in reality they are similar to a central power

station. Comment [A46]: Should this say avoided energy loss?***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 90 of 403 In the April 2012 proposal, we requested comment on requiring the use of net output based standards. Part of the rationale behind that approach is that the use of a gross output-based standard as currently defined could potentially drive the installation of electrically driven feed pumps instead of steam driven feed pumps at a steam generating unit, even though from an overall net efficiency basis it may be more efficient to use steam-driven feed pumps. Subpart Da currently defines gross electric output from steam generating units as the “gross electrical or mechanical output from the affected facility minus any electricity used to power the feedwater pumps and any associated gas compressors (air separation unit main compressor, oxygen compressor, and nitrogen compressor) plus 75 percent of the useful thermal output measured relative to ISO conditions.” We have concluded that the feedwater pump efficiency impacts are primarily relevant to steam generating units, as combustion turbine based generators (and IGCC facilities) typically do not use steam driven feedwater pumps. Therefore, measuring the electric load of these pumps is unnecessarily burdensome for NGCC and IGCC facilities. In addition, we have concluded that measuring the electricity used by gas compressors is also unnecessarily burdensome as they are an inherent part of the currently available IGCC process.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 91 of 403 Therefore, we are proposing the gross electric output for steam generating units be the electricity measured at the generator terminals minus electric power used to run the feedwater pumps, and the gross electric output for IGCC and subpart KKKK affected facilities would be the electricity measured at the generator terminals. We are proposing that with respect to CO 2 emissions, 75 percent credit is the appropriate discount factor for useful thermal output. However, we are requesting comment on a range of two-thirds to three-fourths credit for useful thermal output in the final rule. 2. 60-operating-month rolling average compliance option We also propose a 60-operating-month rolling averaging compliance option that would be available for affected boilersand IGCC facilities. The EPA suggests that this 60-operatingmonth rolling average compliance option will offer operational flexibility and will tend to dampen short-term emission excursions, which may be warranted especially at the initial startup of the facility and the CCS system. We have concluded that this alternative compliance option is not necessary for new stationary combustion turbine EGUs, as they should be able to meet the proposed performance standard with no need for add-on technology. We seek comment on all other aspects of this 60-operating-month rolling averaging compliance***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 92 of 403 option. C. Startup, shutdown, and malfunction requirements 1. Startups and shutdowns Consistent with Sierra Club v. EPA, the EPA is proposing standards in this rule that apply at all times, including during startups and shutdowns. In proposing the standards in this rule, the EPA has taken into account startup and shutdown periods and, for the reasons explained below has not proposed alternate standards for those periods. In the compliance calculation, periods of startup and shutdown are included as periods of partial load. To establish the proposed NSPS’s output-based CO 2 standard, we accounted for periods of startup and shutdown by incorporating them as periods of partial load operation. As noted above, the proposed method to calculate compliance is to sum the emissions for all operating hours and to divide that value by the sum of the electrical energy output and useful thermal energy output, where applicable for CHP EGUs, over a rolling 12-operating-month period. This averaging approach gives more weight to high-load hours and more accurately reflects overall environmental performance. Periods of startup and shutdown will be short, relative to total operating time. Since we are primarily concerned with overall environmental performance over extended periods of time, incorporating Comment [A47]: This case is referenced below, but this appears to be the first reference. Please add full cite.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 93 of 403 relatively short periods of partial load has a negligible effect on measuring performance of the source with respect to long-term efficiency. Thus we allowed that low-load hours do not factor as heavily into the calculated average performance of the source. We solicit comment on any alternative to our proposal that the periods of startup and shutdown be included as periods of partial load in the 12- and 60-operating-month rolling averaging compliance option.

2. Malfunctions Periods of startup, normal operations, and shutdown are all predictable and routine aspects of a source’s operations. However, by contrast, malfunction is defined as a “sudden, infrequent, and not reasonably preventable failure of air pollution control and monitoring equipment, process equipment or a process to operate in a normal or usual manner. Failures that are caused in part by poor maintenance or careless operations are not malfunctions.’’(40 CFR 60.2). The EPA has determined that CAA section 111 does not require that emissions that occur during periods of malfunction be factored into development of CAA section 111 standards. Nothing in CAA section 111 or in case law requires that the EPA anticipate and account for the innumerable types of potential malfunction events in setting emission standards. CAA section 111 provides that the EPA set***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 94 of 403 standards of performance which reflect the degree of emission limitation achievable through ‘‘the application of the best system of emission reduction’’ that the EPA determines is adequately demonstrated. Applying the concept of ‘‘the application of the best system of emission reduction’’ to periods during which a source is malfunctioning presents difficulties. The ‘‘application of the best system of emission reduction’’ is more appropriately understood to include operating units in such a way as to avoid malfunctions. Further, accounting for malfunctions would be difficult, if not impossible, given the myriad different types of malfunctions that can occur across all sources in the category and given the difficulties associated with predicting or accounting for the frequency, degree, and duration of various malfunctions that might occur. As such, the performance of units that are malfunctioning is not “reasonably” foreseeable. See, e.g.,

Sierra Club v EPA , 167 F.3d 658, 662 (D.C. Cir. 1999) (The EPAtypically has wide latitude in determining the extent of datagathering necessary to solve a problem. We generally defer to an agency's decision to proceed on the basis of imperfect scientific information, rather than to "invest the resources to conduct the perfect study."). See also, Weyerhaeuser v. Costle, 590 F.2d 1011, 1058 (DC Cir. 1978) (“In the nature of things, no***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 95 of 403 general limit, individual permit, or even any upset provision can anticipate all upset situations. After a certain point, the transgression of regulatory limits caused by ‘uncontrollable acts of third parties,’ such as strikes, sabotage, operator intoxication or insanity, and a variety of other eventualities, must be a matter for the administrative exercise of case-by-case enforcement discretion, not for specification in advance by regulation”). In addition, the goal of a source that uses the best system of emission reduction is to operate in such a way as to avoid malfunctions of the source and accounting for malfunctions could lead to standards that are significantly less stringent than levels that are achieved by a well-performing non-malfunctioning source. The EPA’s approach to malfunctions is consistent with section 111 and is a reasonable interpretation

of the statute. In the event that a source fails to comply with the applicable CAA section 111 standards as a result of a malfunction event, the EPA would determine an appropriate response based on, among other things, the good faith efforts of the source to minimize emissions during malfunction periods, including preventative and corrective actions, as well as root cause analyses to ascertain and rectify excess emissions. The EPA would also consider whether the source's failure to comply***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 96 of 403 with the CAA section 111 standard was, in fact, “sudden, infrequent, not reasonably preventable” and was not instead “caused in part by poor maintenance or careless operation.” 40 CFR section 60.2 (definition of malfunction). Finally, the EPA recognizes that even equipment that is properly designed and maintained can sometimes fail and that

such failure can sometimes cause a violation of the relevant emission standard. (See, e.g., State Implementation Plans: Response to Petition for Rulemaking; Finding of Excess Emissions During Periods of Startup, Shutdown, and Malfunction; Proposed Rule, 78 FR 12460 (Feb. 22, 2013): (State Implementation Plans: Policy Regarding Excessive Emissions During Malfunctions, Startup, and Shutdown (Sept. 20, 1999); Policy on Excess Emissions During Startup, Shutdown, Maintenance, and Malfunctions (Feb. 15, 1983)). The EPA is therefore proposing to add an affirmative defense to civil penalties for violations of emission standards that are caused by malfunctions. See 40 CFR 60.10042 (defining “affirmative defense” to mean, in the context of an enforcement proceeding, a response or defense put forward by a defendant, regarding which the defendant has the burden of proof, and the merits of which are independently and objectively evaluated in a judicial or administrative proceeding). We also are proposing other regulatory provisions to specify the***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 97 of 403 elements that are necessary to establish this affirmative defense; the source must prove by a preponderance of the

evidence that it has met all of the elements set forth in 60.5530. (See 40 CFR 22.24). The criteria are designed in part to ensure that the affirmative defense is available only where

the event that causes a violation of the emission standard meets the narrow definition of malfunction in 40 CFR 60.2 (sudden, infrequent, not reasonably preventable and not caused by poor maintenance and or careless operation). For example, to successfully assert the affirmative defense, the source must prove by a preponderance of the evidence that the violation “[w]as caused by a sudden, infrequent, and unavoidable failure of air pollution control, process equipment, or a process to operate in a normal or usual manner....” The criteria also are designed to ensure that steps are taken to correct the malfunction, to minimize emissions in accordance with section 60.10001 and to prevent future malfunctions. For example, the source must prove by a preponderance of the evidence that “[r]epairs were made as expeditiously as possible when a violation occurred...” and that “[a]ll possible steps were taken to minimize the impact of the violation on ambient air quality, the environment and human health....” In any judicial or administrative proceeding, the Administrator may challenge the***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 98 of 403 assertion of the affirmative defense and, if the respondent has not met its burden of proving all of the requirements in the affirmative defense, appropriate penalties may be assessed in accordance with section 113 of the CAA (see also 40 CFR part 22.27). The EPA included an affirmative defense in the proposed rule in an attempt to balance a tension, inherent in many types of air regulation, to ensure adequate compliance while simultaneously recognizing that despite the most diligent of efforts, emission standards may be violated under circumstances beyond the control of the source. The EPA must establish emission standards that “limit the quantity, rate, or concentration of emissions of air pollutants on a continuous basis.” 42 U.S.C. §7602(k)(defining “emission limitation” and “emission standard”). See generally Sierra Club v. EPA , 551 F.3d 1019, 1021 (D.C. Cir. 2008) Thus, the EPA is required to ensure

that section 111 emissions standards are continuous. The

affirmative defense for malfunction events meets this requirement by ensuring that even where there is a malfunction, the emission standard is still enforceable through injunctive relief. The United States Court of Appeals for the Fifth Circuit recently upheld the EPA’s view that an affirmative defense provision is consistent with section 113(e) of the Clean Air***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 99 of 403

Act. Luminant Generation Co. LLC v. United States EPA , 2013 U.S. App. LEXIS 6397 (5th Cir. Mar. 25, 2013) 699 F3d. 427(5 th Cir. Oct. 12, 2012) (upholding the EPA’s approval of affirmative defense provisions in a CAA State Implementation Plan). While “continuous” standards, on the one hand, are required, there is also case law indicating that in many situations it is appropriate for the EPA to account for the practical realities of technology. For example, in Essex Chemical v. Ruckelshaus , 486 F.2d 427, 433 (D.C. Cir. 1973), the D.C. Circuit acknowledged that in setting standards under CAA section 111 “variant provisions” such as provisions allowing for upsets during startup, shutdown and equipment malfunction “appear necessary to preserve the reasonableness of the standards as a whole and that the record does not support the ‘never to be exceeded’ standard currently in force.” See also, Portland

Cement Association v. Ruckelshaus , 486 F.2d 375 (D.C. Cir. 1973). Though intervening case law such as Sierra Club v. EPA and the CAA 1977 amendments call into question the relevance of these cases today, they support the EPA’s view that a system that incorporates some level of flexibility is reasonable. The affirmative defense simply provides for a defense to civil penalties for violations that are proven to be beyond the control of the source. By incorporating an affirmative defense, Comment [A48]: The relevance is questioned with respect to other issues? Add clarifying statement.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 100 of 403 the EPA has formalized its approach to malfunctions. In a Clean Water Act setting, the Ninth Circuit required this type of formalized approach when regulating “upsets beyond the control of the permit holder.” Marathon Oil Co. v. EPA , 564 F.2d 1253, 1272-73 (9 th Cir. 1977). See also , Mont. Sulphur & Chem. Co. v.

United States EPA , 666 F.3d. 1174 (9 th Cir. 2012)(rejecting industry argument that reliance on the affirmative defense was not adequate). But see, Weyerhaeuser Co. v. Costle , 590 F.2d 1011, 1057-58 (D.C. Cir. 1978) (holding that an informal approach is adequate). The affirmative defense provisions give the EPA the flexibility to both ensure that its emission standards are “continuous” as required by 42 U.S.C. §7602(k), and account for unplanned upsets and thus support the

reasonableness of the standard as a whole. We propose that these same requirements, an affirmative defense to civil penalties for violations of emission limits that are caused by malfunctions, would apply to both the 12- operating-month standard and the 60-operating-month rolling average compliance option; however, we will take comment on whether it is appropriate to have an affirmative defense for the 60-operating-month rolling average portion of that compliance option, given that we would expect malfunctions to only impact shorter averaging periods, and the longer the compliance period,***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 101 of 403 the less likely malfunction events are to impact a source’s ability to meet the standard. D. Continuous monitoring requirements Today’s proposed rule would require owners or operators of EGUs that combust solid fuel to install, certify, maintain, and operate continuous emission monitoring systems (CEMS) to measure

CO 2 concentration, stack gas flow rate, and (if needed) stack gas moisture content in accordance with 40 CFR Part 75, in order to determine hourly CO 2 mass emissions rates (tons/hr). The proposed rule would allow owners or operators of EGUs that burn exclusively gaseous or liquid fuels to install fuel

flow meters as an alternative to CEMS and to calculate the hourly CO 2 mass emissions rates using Equation G-4 in Appendix G of Part 75. To implement this option, hourly measurements of fuel flow rate and periodic determinations of the gross calorific value (GCV) of the fuel are also required, in accordance with Appendix D of Part 75. In addition to monitoring the CO 2 mass emission rate, the proposed rule would require EGU owners or operators to monitor the hourly unit operating time and “gross output”, expressed in megawatt hours (MWh). The gross output includes electrical output plus any mechanical output, plus 75 percent of any useful thermal output.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 102 of 403 The proposed rule would require EGU owners or operators to prepare and submit a monitoring plan that includes both electronic and hard copy components, in accordance with §§75.53(g) and (h). The electronic portion of the monitoring plan would be submitted to the EPA’s Clean Air Markets Division (CAMD) using the Emissions Collection and Monitoring Plan System (ECMPS) Client Tool. The hard copy portion of the plan would be sent to the applicable State and EPA Regional office. Further, all monitoring systems used to determine the CO 2 mass emission rates would have to be certified according to §75.20 and section 6 of Part 75, Appendix A within the 180-day window of time allotted under §75.4(b), and would be required to meet the applicable on-going quality assurance procedures in Appendices B

and D of Part 75. The proposed rule would require all valid data recorded by the monitoring systems (including data recorded during startup, shutdown, and malfunction) to be used in assessing compliance. Failure to collect required data is a violation of the monitoring requirements, except for periods of monitoring system malfunctions, repairs associated with monitoring system malfunctions, and required monitoring system quality assurance or quality control activities that temporarily interrupt the measurement of stack emissions (e.g., calibration error tests,***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 103 of 403 linearity checks, and required zero and span adjustments). An affirmative defense to civil penalties for malfunctions is

available to a source if it can demonstrate that certain criteria and requirements are satisfied. The proposed rule would require only those operating hours in which valid data are collected for all of the parameters in

the CO 2 mass emission rate equation to be used for compliance purposes. Additionally for EGUs using CO 2 CEMS, only unadjusted stack gas flow rate values would be used in the emissions calculations. In this proposal, Part 75 bias adjustment factors (BAFs) would not be applied to the flow rate data. These restrictions on the use of Part 75 data for Part 60 compliance are consistent with previous NSPS regulations and revisions. The following variations from and additions to the basic Part 75 monitoring would be required:

 If you determine compliance using CEMS, you would be required to use a laser device to measure the stack

diameter at the flow monitor and the reference method sampling locations prior to the initial setup (characterization) of the flow monitor. For circular stacks, you would make three determinations of the diameter and average the results. For rectangular stacks or ducts, you would make three measurements of each***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 104 of 403 dimension (i.e., depth and width) and average the results. If the flow rate monitor or reference method sampling site is relocated, you would repeat these measurements at the

new location.

 If you elect to use Method 2 in Appendix A-1 of Part 60 to perform the required relative accuracy test audits (RATAs) of the Part 75 flow rate monitoring system, you would have to use a calibrated Type-S pitot tube or pitot tube assembly. Use of the default Type-S pitot tube coefficient would not be permitted.

 If your EGU combusts natural gas and/or fuel oil and you

elect to measure the CO 2 mass emissions rate using Equation G-4 in Appendix G of Part 75, you would be allowed to determine site-specific carbon-based F-factors using Equation F-7b in section 3.3.6 of Appendix F of Part 75, and you could use these F c values in the emissions calculations instead of using the default F c values in the Equation G-4 nomenclature. Today’s proposed rule includes the following special compliance provisions for units with common stack or multiple stack configurations; these provisions are consistent with §60.13(g):***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 105 of 403

 If two or more of your EGUs share a common exhaust stack, are subject to the same emission limit, and you are required to (or elect to) determine compliance using CEMS, you would be allowed to monitor the hourly CO 2 mass emission rate at the common stack instead of monitoring each EGU separately. If this option is chosen, the hourly gross electrical load (or steam load) would be the sum of the hourly loads for the individual EGUs and the operating time would be expressed as “stack operating hours” (as defined in 40 CFR 72.2). Then, if compliance with the applicable emission limit is attained at the common stack, each EGU sharing the stack would be considered to be in compliance.

 If you are required to (or elect to) determine compliance using CEMS and the effluent from your EGU discharges to the atmosphere through multiple stacks (or, if the effluent is fed to a stack through multiple ducts and you choose to monitor in the ducts), you would be required to monitor the hourly CO 2 mass emission rate and the “stack operating time” at each stack or duct separately. In this case, compliance with the applicable emission limit would be determined by summing the CO 2 mass emissions measured at***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 106 of 403 the individual stacks or ducts and dividing by the total gross output for the unit. The proposed rule would require 95 percent of the operating hours in each compliance period (including the compliance periods for the intermediate emission limits to be “valid hours,” i.e., operating hours in which quality-assured data are obtained for all of the parameters used to calculate CO 2 mass emissions. EGU owners or operators would have the option to use backup monitoring systems, as provided in §§75.10(e) and 75.20(d), to help meet this proposed data capture requirement. E. Emissions performance testing requirements In accordance with §75.64(a), the proposed rule would require an EGU owner or operator to begin reporting emissions data when monitoring system certification is completed or when the 180-day window in §75.4(b) allotted for initial certification of the monitoring systems expires (whichever date is earlier). For EGUs subject to the 450 kg/MWh (1,000 lb/MWh) standard or the 500 kg/MWh (1,100 lb/MWh) emission standard, the initial performance test would consist of the first 12- operating-months of data, starting with the month in which emissions are first required to be reported. The initial 12- operating-month compliance period would begin with the first month of the first calendar year of EGU operation in which the***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 107 of 403 facility exceeds the capacity factor applicability threshold. The traditional 3-run performance tests (i.e., stack tests) described in §60.8 would not be required for this rule. Following the initial compliance determination, the emission standard would be met on a 12-operating-month rolling average basis. For EGUs that combust coal and/or petroleum coke and whose owners or operators elect to comply with the alternative 60-operating-month rolling average emissions standard, the first month in the compliance period would be the month in which emissions reporting is required to begin under §75.64(a). F. Continuous compliance requirements Today’s proposed rule specifies that compliance with the 450 kg/MWh (1,000 lb/MWh) and 500 kg/MWh (1,100 lb/MWh) CO 2 massemissions rate limits would be determined on a 12-operatingmonth rolling average basis, updated after each new operatingmonth. For each 12-operating-month compliance period, qualityassured data from the certified Part 75 monitoring systems would be used together with the gross output over that period of time to calculate the average CO 2 mass emissions rate. The proposed rule specifies that the first operating month included in either the initial 12- or 60-operating-month compliance period would be the month in which reporting of emissions data is required to begin under §75.64(a), i.e., Comment [A49]: In most instances, the rule lists the lb/Mwh - suggest putting kg/MWh in parenthesis here for consistency.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 108 of 403 either the month in which monitoring system certification is completed or the month in which the 180-day window allotted to finish certification testing expires (whichever month is earlier). We are proposing that initial compliance with the applicable emissions limit in kg/MWh be calculated by dividing the sum of the hourly CO 2 mass emissions values by the total gross output for the 12- or 60-operating-month period. Affected EGUs would continue to be subject to the standards and maintenance requirements in the section 111 regulatory general provisions contained in 40 CFR part 60, subpart A. G. Notification, recordkeeping, and reporting requirements Today’s proposed rule would require an EGU owner or operator to comply with the applicable notification requirements in §75.61, §§60.7(a)(1) and (a)(3) and §60.19. The proposed rule would also require the applicable recordkeeping requirements in subpart F of Part 75 to be met. For EGUs using CEMS, the data elements that would be recorded include, among others, hourly CO 2 concentration, stack gas flow rate, stack gas moisture content (if needed), unit operating time, and gross electric generation. For EGUs that exclusively combust liquid and/or gaseous fuel(s)

and elect to determine CO 2 emissions using Equation G-4 in Appendix G of Part 75, the key data elements in subpart F that***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 109 of 403 would be recorded include hourly fuel flow rates, fuel usage times, fuel GCV, gross electric generation. The proposed rule would require EGU owners or operators to keep records of the calculations performed to determine the

total CO 2 mass emissions and gross output for each operating month. Records would be kept of the calculations performed to determine the average CO 2 mass emission rate (kg/MWh) and the percentage of valid CO 2 mass emission rates in each compliance period. The proposed rule would also require records to be keptof calculations performed to determine site-specific carbonbased F-factors for use in Equation G-4 of Part 75, Appendix G (if applicable). For EGU owners or operators who would elect to comply with the 60-operating-month rolling average emissions standard, records must be kept for 10 years. All other records would be kept for a period of three years. All required records would be kept on-site for a minimum of two years, after which the records

could be maintained off-site. The proposed rule would require all affected EGU owners/operators to submit quarterly electronic emissions reports in accordance with subpart G of Part 75. The proposed rule would require these reports to be submitted using the ECMPS Client Tool. Except for a few EGUs that may be exempt from the***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 110 of 403 Acid Rain Program (e.g., oil-fired units), this is not a new reporting requirement. Sources subject to the Acid Rain Program are already required to report the hourly CO 2 mass emission rates that are needed to assess compliance with today’s rule. Additionally, in the proposed rule and as part of an Agency-wide effort to streamline and facilitate the reporting of environmental data, the rule would require selected data elements that pertain to compliance under this rule, and that serve the purpose of traditional excess emissions reports, to be reported periodically using ECMPS. Specifically, for EGU owners/operators who would comply with a 12-operating-month rolling average standard, quarterly electronic “excess emissions” reports must be submitted, within 30 days after the end of each quarter. The first report would be for the quarter that includes the final (12 th ) operating month of the initial 12 operating month compliance period. For that initial report and any subsequent report in which the twelfth operating month of a compliance period (or periods) occurs during the calendar quarter, the average CO 2 mass emissions rate (kg/MWh) would be reported for each compliance period, along with the dates (year and month) of the first and twelfth operating months in the compliance period and the percentage of

valid CO 2 mass emission rates obtained in the compliance period.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 111 of 403 The dates of the first and last operating months in the compliance period would clearly bracket the period used in the determination, which facilitates auditing of the data. Reporting the percentage of valid CO 2 mass emission rates is necessary to demonstrate compliance with the requirement to obtain valid data for 95 percent of the operating hours in each compliance period. Any excess emissions that occur during the quarter would be identified. If there are no compliance periods that end in the quarter, a definitive statement to that effect would be included in the report. If one or more compliance periods end in the quarter but there are no excess emissions, a statement to that effect would be included in the report. For EGU owners or operators that would comply with a 60- operating-month rolling average basis, quarterly electronic “excess emissions” reports would be submitted, within 30 days after the end of each quarter. The first report would be for the quarter that includes the final (60 th ) operating month of the initial 60-operating-month compliance period. For that initial report and any subsequent report in which the sixtieth operating month of a compliance period (or periods) occurs during the calendar quarter, the average CO 2 mass emissions rate (kg/MWh) must be reported for each compliance period, along with the dates (year and month) of the first and sixtieth operating***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 112 of 403 months in the compliance period and the percentage of valid CO 2 mass emission rates obtained in the compliance period. The dates of the first and last operating months in the compliance period would clearly bracket the period used in the determination, which facilitates auditing of the data. Reporting of the percentage of valid CO 2 mass emission rates is necessary to demonstrate compliance with the requirement to obtain valid data for 95 percent of the operating hours in each compliance period. Any excess emissions that occur during the quarter would be identified. If there are no compliance periods that end in the quarter, a definitive statement to that effect would be included in the report. If one or more compliance periods end in the quarter but there are no excess emissions, a statement to that effect would be included in the report. Currently, ECMPS is not programmed to receive excess emission report information. However, we will make the necessary modifications to the system in order to fully implement the reporting requirements of this rule upon promulgation. **IV. Rationale for Reliance on Rational Basis to Regulate GHGs**

**from Fossil-fired EGUs**

A. Overview In our original proposal, we proposed and solicited comment on what basis we are required to have concerning the health and Comment [A50]: From any source category? Or, just from EGUs? Consider clarifying.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 113 of 403 welfare impacts of GHG emissions from fossil-fuel fired power plants in order to regulate those emissions under CAA §111. However, we took the position that we are not required to make findings that GHGs from fossil-fired power plants “cause[], or contribute[] significantly to, air pollution which may reasonably be anticipated to endanger public health or welfare,” under CAA §111(b)(1)(A). We have reconsidered that proposal in light of the numerous comments we received. In today’s notice, we propose that the EPA has a rational basis for promulgating standards for GHG emissions from electricity generating plants because the EPA has already determined that GHG emissions may reasonably be anticipated to endanger public health and welfare; and electricity generating plants, as an industry, constitute, by a significant margin, the largest emitters in the inventory. In the April 2012 proposal, the EPA discussed whether CAA section 111 requires that the EPA issue, as a prerequisite for this rulemaking, another “endangerment” finding. After reviewing the comments, recent scientific developments, the amount of emissions from the power plant sector, and the case law, the EPA has concluded that section 111 requires only that the EPA establish a rational basis for regulating GHG emissions from power plants, but that even if an endangerment finding were***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 114 of 403 required, the rational basis described in today’s action would qualify as an endangerment finding as well. As related matters, in this notice, we are proposing to establish regulatory requirements for CO 2 emissions of affected units, which are included in a source category that the EPA already listed under CAA §111(b)(1)(A) for regulation under CAA and we are not proposing a new listing of a source category. We are, however, proposing to subcategorize different sets of sources, and establish different CO 2 standards of performance for them, in accordance with CAA §111(b)(2). To avoid confusion, we are proposing to codify the CO 2 standards of performance in the same subparts – Da and KKKK, depending on the types of units – that currently include the standards of performance for conventional pollutants, instead of codifying the CO 2 standards in a new subpart. B. Climate Change Impacts from GHG Emissions; Amounts of GHGs

from fossil fuel-fired EGUs In 2009, the EPA Administrator issued the Endangerment Finding under CAA section 202(a)(1). With the Endangerment Finding, the Administrator found that elevated concentrations of GHGs in the atmosphere may reasonably be anticipated to endanger public health and welfare of current and future generations, focused on public health and public welfare impacts within the***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 115 of 403 United States. Fossil fuel-fired EGUs are by far the largest emitters of GHGs, primarily in the form of CO 2 , among stationary sources in the U.S. These adverse effects of GHGs on public health and welfare, and the amounts of GHGs emitted by fossil fuel-fired EGUs are briefly summarized in the background section of this preamble, described in more detail in the RIA, and need

not be recited here. C. CAA §111 requirements To review the key CAA §111 requirements: CAA §111(b)(1)(A), by its terms, requires that the Administrator shall publish (and from time to time thereafter shall revise) a list of categories of stationary sources. He shall include a category of sources in such list if in his judgment it causes, or contributes significantly to air pollution which may reasonably be anticipated to endanger public health or welfare. CAA §111(b)(1)(B) goes on to provide that after listing the source category, the EPA must promulgate regulations “establishing federal standards of performance for new sources within such category.” In turn, CAA §111(a)(1) defines a “standard of performance” as a “standard for emissions of air pollutants which reflects the degree of emission reduction which (taking into account ... cost ... and any nonair quality health and environmental impact and energy requirements) ... has been adequately demonstrated.” CAA §111(b)(2) provides that “The Administrator may distinguish among classes, types, and sizes***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 116 of 403 within categories of new sources for the purpose of establishing

such standards.” D. Interpretation of CAA §111 requirements CAA §111(b)(1)(A) requires the EPA to list a source category if it contributes significantly to air pollution that endangers public health or welfare. The EPA must necessarily conduct this listing by making determinations as to the health or welfare impacts of one or more of the pollutants emitted by that source category, or the pollution to which the source category contributes and as to the significance of the amount of such contribution. However, by the terms of CAA §111(b)(1)(A), the EPA may make these determinations on the basis of the impacts of all of the source category’s pollutants taken as a whole. Nothing in CAA §111(b)(1)(A) requires that the EPA make separate determinations for each pollutant. After listing a source category, the EPA must proceed to promulgate standards of performance for the source category’s pollutants under CAA §111(b)(1)(B) and 111(a)(1). However, nothing in those provisions requires that, at the time when the EPA promulgates the standards of performance for the individual pollutants, the EPA must make a determination as to the health or welfare effects of those particular pollutants or as to the significance of the amount of the source category’s emissions of***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 117 of 403 those pollutants. Clearly, CAA §111 does not by its terms require that as a prerequisite for the EPA to promulgate a standard of performance for a particular pollutant, the EPA must first find that the pollutant causes or contributes significantly to air pollution that endangers public health or welfare. The lack of any such requirement contrasts with other CAA provisions that do require the EPA to make endangerment and cause-or-contribute findings for the particular pollutant that the EPA regulates under those provisions. E.g., CAA sections 202(a)(1), 211(c)(1), 231(a)(2)(A). The lack of any express requirement in CAA section 111 addressing whether and how the EPA is to evaluate emissions of a particular pollutant from the listed source category as a prerequisite for promulgation of a standard of performance is properly viewed as a statutory gap that requires the EPA to make

what we refer to as a Chevron step 2 interpretation. Under the U.S. Supreme Court’s 1984 decision in Chevron U.S.A. Inc. v.

NRDC , 71 to interpret how a statute applies to a particular question, an agency must, at Step 1, determine whether Congress’s intent as to the specific question is clear, and, if so, the agency must give effect to that intent. If congressional intent is not clear, then the agency, at Step 2, has discretion

71 467 U.S. 837 (1984).***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 118 of 403 to fashion an interpretation that is a reasonable construction

of the statute. 72 In this case, the EPA is authorized to develop a reasonable interpretation. Our interpretation is that in order to promulgate a §111 standard of performance for a particular pollutant, we do not need to make a pollutant-specific endangerment finding, but instead must demonstrate a rational basis for controlling the emissions of the pollutant. That rational basis may be based on information concerning the health and welfare impacts of the air pollution at issue, and the amount of contribution that the source category’s emissions make to that air pollution. Commenters on the April 2012 proposal stated that the EPA is required to make an endangerment finding for CO 2 because when the EPA listed this source category, it was on the basis of other pollutants, and not CO 2 . However, CAA §111(b)(1)(A) by its terms requires that the EPA “shall publish (and from time to time thereafter, shall revise) a list of categories of stationary sources,” and that the EPA shall list “a category of sources” based on the EPA’s judgment that the category “causes, or contributes significantly to, air pollution” that endangers public health or welfare. Thus, this provision requires that the EPA make the listing decision on a category basis, and not on a

72 Id. at 842-43.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 119 of 403 pollutant-by-pollutant basis. That is, this provision does not require that the EPA establish separate lists of source categories, with each list covering a different pollutant. Therefore, this provision does not require that the EPA make an endangerment finding on a pollutant by pollutant basis. Commenters on the April 2012 proposal stated that the EPA was required to make an endangerment finding because by creating the new subpart TTTT in 40 CFR, the EPA was listing the source category that included the affected units. However, in neither the original proposal nor this new proposal has EPA proposed to list a new source category. The EPA initially included fossil fuel-fired EGUs (which includes EGUs that burn fossil fuel including coal, gas, oil and petroleum coke and that use different technologies, including boilers and combustion turbines) in a category that it listed under section 111(b)(1)(A) and promulgated the first set of standards of performance for EGUs in 1971, codified in subpart D. 73 The EPA has revised those regulations, and in some instances, revised the subparts, several times over the ensuing

decades. In 1979, the EPA divided subpart D into 3 subparts – Da

73 “Standards of Performance for Fossil-Fuel-Fired Steam Generators for Which Construction Is Commenced After August 17, 1971,” 36 Fed. Reg. 24875 (Dec. 23, 1971) codified at 40 CFR 60.40-46; 36 Fed. Reg. 5931 (Mar. 31, 1971).***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 120 of 403 (“Standards of Performance for Electric Utility Steam Generating Units for Which Construction is Commenced After September 18,1978”), Db (“Standards of Performance for Industrial-CommercialInstitutional Steam Generating Units”) and Dc (“Standards of

Performance for Small Industrial-Commercial-Institutional Steam Generating Units”) – in order to codify separate requirements that it established for these subcategories. 74 In 2006, the EPA created subpart KKKK, ”Standards of Performance for Stationary Combustion Turbines,” which applied to certain sources from multiple subparts

. 75 None of these rulemakings or codifications, however, constituted a new listing under CAA §111(b)(1)(A). In today’s rulemaking, similarly to the original proposal, the EPA is not proposing to list a new category of sources. Rather, the EPA is simply promulgating new standards of performance for CO 2 emissions from certain sets of sources, e.g., boilers and turbines, but not liquid-fired sources. Moreover, we are establishing different requirements for different sets of sources, including smaller and larger combustion turbines, and boilers, in accordance with CAA §111(b)(2). That provision

74 44 Fed. Reg. 33,580 (June 11, 1979) 75 71 Fed. Reg. 38497 (July 6, 2006), as amended at 74 Fed. Reg. 11861 (Mar. 20, 2009).***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 121 of 403 authorizes the EPA to “distinguish among classes, types, and sizes within categories of new sources for the purpose of establishing ... standards [of performance.]” 76 We recognize that our original proposal, by codifying these new standards of performance in a separate subpart, TTTT, may have led to some confusion over whether the new subpart under the EPA’s regulations constituted a new listing under CAA §111(b)(1)(A). That was not the case, for the reasons noted above, but to minimize confusion, we are taking a different approach in this proposal, and are codifying the new CO 2 standards in the same subparts in which the standards of performance for conventional pollutants are codified. Thus, we are codifying the standards for solid-fuel fired EGUs as a new section in subpart Da, and the standards for turbines as new sections in subpart KKKK.E. Rational basis to promulgate standards for GHGs from fossilfired EGUs In this rulemaking, the air pollution in question is GHGs, and the EPA has a rational basis for concluding that this air

76 For this same reason, EPA’s notice today does not propose to revise the list. Though EPA in the April 2012 proposed rule preamble pointed to the authority to revise the list as a basis for the proposed rule, see 77 FR at 22398, upon further consideration EPA has concluded that our proposal does not constitute a revision to the list of categories for the reasons discussed above.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 122 of 403 pollution merits taking action under CAA §111. As noted, in 2009, the EPA made a finding that GHG air pollution may reasonably be anticipated to endanger public health or welfare, and in 2010, the EPA denied petitions to reconsider that finding. The EPA extensively reviewed the available science concerning GHG pollution and its impacts in taking those actions. In 2012, the U.S. Court of Appeals for the D.C. Circuit upheld the finding and denial of petitions to reconsider. In addition, assessments from the NRC and the IPCC, published in 2010, 2011, and 2012 lend further credence to the validity of the Endangerment Finding. As discussed below, no information that commenters have presented or that the EPA has reviewed provides a basis for rescinding that finding. In addition, as noted, the high level of GHG emissions from the fossil-fired EGUs makes clear that it is rational for the EPA to regulate GHG emissions from this sector. This information amply supports that the EPA has a rational basis for promulgating regulations under CAA §111 designed to address GHG air pollution.

Our conclusion is consistent with the case law handed down by the D.C. Circuit. In its 1980 decision in National Lime

Association v. EPA , 77 the Court upheld EPA’s determination that lime manufacturing plants emit particulates that contribute

77 627 F.2d 416 (D.C. Cir. 1980).***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 123 of 403 significantly to air pollution that endangers public health or welfare. The Court noted that (i) EPA’s basis was its prior determination that “the significant production of particulate emissions ... cause[s] or contribute[s] to air pollution (which may reasonably be anticipated to endanger public health or welfare);” and (ii) “[t]he Agency has made this determination for purposes of establishing national primary and secondary ambient air quality standards under [CAA §109].” The Court held: We think the danger of particulate emissions' effect on health has been sufficiently supported in the Agency's (and its predecessor's) previous determinations to provide a rational basis for the Administrator's finding in this case. 78 Similarly, in National Asphalt Pavement Ass’n v. Train, 79 the D.C. Circuit upheld a determination by the EPA that asphalt cement plants contribute significantly to particulate matter air pollution that endangers public health and welfare. The Court indicated that the EPA’s determination that particulate matter endangers is valid simply on grounds that the EPA established a NAAQS for that pollutant. 80 These cases support our relying primarily on the analysis and conclusions in our previous Endangerment Finding, and the subsequent assessments, as providing a rational basis for our

78 Id. at 431-32 n.48. 79 539 F.2d 775 (D.C. Cir. 1976) 80 Id. at 784***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 124 of 403 decision to impose standards of performance on GHG emissions

from fossil-fuel fired EGUs. Commenters state that because the proposed rulemaking limits emissions of only CO 2 , and not other GHGs, the EPA cannot rely on the analysis and conclusions in the 2009 Endangerment Finding because it concerned a mix of six GHGs: carbon dioxide and five others. These commenters assert that as a prerequisite for the present rulemaking, the EPA must make an endangerment finding for CO 2 alone. Commenters’ assertion here is incorrect for two reasons. First, as discussed above, the EPA does not need to make a formal endangerment finding with respect to a particular pollutant to set standards for that pollutant under section 111(b)(1)(B). Second, the EPA may reasonably rely on the analysis and conclusions in the 2009 Endangerment Finding on GHGs because, with respect to this proposed rulemaking, the air pollution at issue here is the mix of six GHGs. It is that air pollution that has caused the various impacts on health and welfare that formed the basis for the Endangerment Finding. Further, the CO 2 emissions from EGUs cause or contribute significantly to that air pollution. As we noted in the 2009 Endangerment Finding, CO 2 is the “dominant anthropogenic Comment [A51]: This sentence is quite bulky. Consider whether the highlighted text could be deleted in this sentence, and then redrafted as a new sentence that follows the final clause in this sentence. In some way, this “Second,” sentence should be drafted to be more concise and straightforward.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 125 of 403 greenhouse gas.” 81 The fact that we are not regulating the other five GHGs in this rulemaking does not mean that we are required to identify the air pollution as CO 2 rather than GHGs. This is consistent with the EPA past actions. In the 2010 Light Duty Vehicle Rule for which the Endangerment Finding served as the predicate, the EPA regulated only four of the GHGs, not all

six. 82 Further, the fact that affected EGUs emit almost 1/3 of all U.S. GHGs and comprise by far the largest stationary source category of GHG emissions, as discussed above, provides a rational basis for regulating CO 2 emissions from affected EGUs. Indeed, so great is the contribution of CO 2 air pollutants from EGUs to GHG air pollution, that it is simply not necessary in this rulemaking to determine the specific threshold for when a contribution may be considered to be a “significant[]”

contribution. 83 There can be no question that whatever that threshold may be, GHG emissions from fossil-fuel fired EGUs

81 [placeholder: Cite 82 [placeholder: Cite to Light Duty Vehicle Rule. 83 Commenters on the original proposal stated that new solid-fuel fired power plants made no contribution to air pollution because EPA’s modeling projected no new construction of those types of plants. However, CAA §111(b)(1)(A) is clear by its terms that the source category listing that is the prerequisite to regulation is based on the contribution of the “category” to air pollution, and therefore is not based on the contribution of only new sources in the category.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 126 of 403

exceed it. 84 This is consistent with previous EPA actions that have been upheld by the D.C. Circuit. In the National Lime

Association v. EPA case, noted above, the Court upheld the EPA’s regulation of lime plants on grounds that they were one of the largest -- although not within the largest 10 percent -- emitting industries of particulates. The Court stated, EPA ... focused ...on the sheer quantity of dust generated by lime plants. 42 Fed.Reg. 22507 (“A study performed for EPA in 1975 by the Research Corporation of New England ranked the lime industry twenty-fifth on a list of 112 stationary sources categories which are emitters of particulate matter”); SSEIS 8-2 (“In a study performed for EPA by Argonne National Laboratory in 1975, the lime industry ranked seventh on a list of the 56 largest particulate source categories in the U.S.”). 85 In the National Asphalt Pavement Ass’n v. Train case, noted above, the Court upheld the EPA’s determination that the asphalt industry contributed significantly to the air pollution based on “the number of existing plants, the expected rate of growth in the number of plants, the rate of uncontrolled emissions, and the level of emissions currently tolerated.” 86 F. Alternative findings of endangerment and significant

contribution

84 Indeed, it is literally true that if fossil-fuel fired EGUs cannot be found to contribute significantly to GHG air pollution, then there is no source category in the U.S. that does contribute significantly to GHG air pollution, a result that would defeat the purposes of CAA §111. 85 627 F.2d at 432, n.48. 86 539 F.2d at 784-85.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 127 of 403 Even if CAA section 111 is interpreted to require that the EPA make endangerment and cause-or-contribute significantly findings as prerequisites for today’s rulemaking, then our rational basis, as described, should be considered to constitute those findings. As noted above, the EPA’s rational basis for regulating under §111 GHGs is based primarily on the analysis and conclusions in the EPA’s 2009 Endangerment Finding and 2010 denial of petitions to reconsider that Finding, coupled with the 2010, 2011, and 2012 assessments from the IPCC and NRC that describe scientific developments since those EPA actions. In addition, as noted above, we would review comments presenting

other scientific information to determine whether that information has any meaningful impact on our primary basis. This rational basis approach is substantially similar to the approach the EPA took in the 2009 Endangerment Finding and the 2010 denial of petitions to reconsider. As noted, the D.C. Circuit upheld that approach in the CRR case. Accordingly, that approach would support an endangerment finding for this rulemaking. By the same token, if the EPA were required to make a cause-or-contribute-significantly finding for CO 2 emissions from the fossil fuel-fired EGUs, as a prerequisite to regulating such***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 128 of 403 emissions under CAA §111, the same facts that support our rational basis determination would support such a finding. In particular, fossil fuel-fired EGUs emit almost 1/3 of all U.S. GHG emissions, and constitute by far the largest single stationary source category of GHG emissions. Thus, even if the EPA were required to make a cause-or-contribute-significantly finding as part of setting standards under section 111(b)(1)(B), it would not be necessary for the EPA to identify a specific threshold for the amount of emissions from a source category that constitutes a significant contribution. Under any reasonable threshold or definition, the emissions from EGUs are a significant contribution. G. Comments on the state of the science of climate change The EPA received a number of comments in response to the proposed NSPS rule that addressed the scientific underpinnings of the EPA’s 2009 Endangerment Finding and, in essence, the scientific justification for this rule. The EPA has carefully reviewed all of those comments, and responses to those comments are provided in the Response to Comments document for this action. It is important to place these comments in the context of the voluminous record on this subject that has been compiled over the last few years. This includes: 1) the process by which the Administrator reached the 2009 finding that GHGs are***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 129 of 403 reasonably anticipated to endanger the public health and welfare of current and future generations; 2) the EPA’s response in 2010 to ten administrative petitions for reconsideration of the Endangerment Finding, the “Reconsideration Denial”; and, 3) the decision by the United States Court of Appeals for the DC Circuit (DC Circuit Court) in 2012 to uphold the Endangerment Finding and the Reconsideration Denial. As outlined in Section VIII.A. of the 2009 Endangerment Finding, the EPA’s approach to providing the technical and scientific information to inform the Administrator’s judgment regarding the question of whether GHGs endanger human health and welfare was to rely primarily upon the recent, major assessments by the U.S. Global Change Research Program (USGCRP), the Intergovernmental Panel on Climate Change (IPCC), and the National Research Council (NRC) of the National Academies. In brief, these assessments addressed the scientific issues that the EPA was required to examine, were comprehensive in their coverage of the GHG and climate change problem, and underwent rigorous and exacting peer review by the expert community, as well as rigorous levels of U.S. government review and acceptance, in which the EPA took part. The EPA received thousands of comments on the proposed Endangerment Finding and responded to them in depth in an 11-volume Response to Comments***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 130 of 403 (RTC) document. While the EPA gave careful consideration to all of the scientific and technical information received, it placed less weight on the much smaller number of individual studies that were not considered or reflected in the major assessments— often these studies were published after the submission deadline for those larger assessments. Primary reliance on the major scientific assessments provided the EPA greater assurance that it was basing its judgment on the best available, well-vetted

science that reflected the consensus of the climate science community, rather than selecting the studies it would rely on. Nonetheless, the EPA reviewed individual studies not incorporated in the assessment literature to see if they would lead the EPA to change its interpretation of, or place less weight on, the major findings reflected in the assessment reports. From its review of individual studies submitted by commenters, the EPA concluded that these studies did not change the various conclusions or judgments the EPA would draw based on the more comprehensive assessment reports. The major findings of the USGCRP, IPCC, and NRC assessments supported the EPA’s determination that GHGs threaten the public health and welfare of current and future generations. The EPA demonstrated this scientific support at length in the Endangerment Finding itself,***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 131 of 403 in its Technical Support Document (which summarized the findings of USGCRP, IPCC and NRC), and in its RTC document. The EPA then reviewed ten administrative petitions for reconsideration of the Endangerment Finding in 2010. The Administrator denied those petitions in the “Reconsideration Denial” on the basis that the Petitioners failed to provide substantial support for the argument that the Endangerment Finding should be revised and therefore their objections were not of “central relevance” to the Finding. 87 The EPA prepared an accompanying 3-volume Response to Petitions (RTP) document to provide additional information, often more technical in nature, in response to the arguments, claims, and assertions by the petitioners to reconsider the Endangerment Finding. The 2009 Endangerment Finding and the 2010 Reconsideration Denial were challenged in a lawsuit; on June 26, 2012, the DC Circuit Court upheld the Endangerment Finding and the Reconsideration Denial, ruling that the Finding was neither arbitrary nor capricious, was consistent with Massachusetts v.

EPA, 88 and was adequately supported by the administrative

87 EPA’s Denial of the Petitions To Reconsider the Endangerment and Cause or Contribute Findings for Greenhouse Gases Under Section 202(a) of the Clean Air Act (“Reconsideration Denial”), 75 Fed. Reg. 49,556, 58 (Aug. 13, 2010). 88 Massachusetts v. EPA, 549 U.S. 497.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 132 of 403

record. 89 The Court found that the EPA had based its decision on “substantial scientific evidence,” 90 noted that the EPA’s

reliance on assessments was consistent with the methods decision-makers often use to make a science-based judgment, 91 and stated that “EPA’s interpretation of the governing CAA provisions is unambiguously correct.” 92 The Court also found that the Petitioners had “not provided substantial support for their argument that the Endangerment Finding should be revised.” 93 Moreover, the Court assessed the EPA’s reliance on the major scientific assessment reports conducted by USGCRP, IPCC, and NRC, and subjected to rigorous expert and government review, and found that “EPA evaluated the processes used to develop the various assessment reports, reviewed their contents, and considered the depth of the scientific consensus the reports represented. Based on these evaluations, the EPA determined the assessments represented the best source material to use in deciding whether GHG emissions may be reasonably anticipated to endanger public health or welfare.” 94 As the Court stated, “It

makes no difference that much of the scientific evidence in

89 Coalition for Responsible Regulation, Inc. v. EPA , 684 F.3d 102 (D.C. Cir. 2012). 90 Ibid at 121. 91 Ibid at 120. 92 Ibid at 113. 93 Ibid at 125. 94 Ibid at 120.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 133 of 403 large part consisted of ‘syntheses’ of individual studies and research. Even individual studies and research papers often synthesize past work in an area and then build upon it. This is how science works. The EPA is not required to re-prove the existence of the atom every time it approaches a scientific question.” 95 It is within the context of this extensive record, and recent affirmation of the Endangerment Finding by the Court,

that the EPA has considered all of the submitted science-related comments and reports for the April 2012 proposed rule, and will consider any further comments in response to today’s proposed rule. As it did in the original Endangerment Finding, the EPA is giving careful consideration to all of the scientific andtechnical information in the record. However, the major peerreviewed scientific assessments continue to provide the primary scientific and technical basis upon which the Administrator’s judgment relies regarding the threat to public health and welfare posed by GHGs. Commenters on the April 2012 proposed rule submitted two major peer-reviewed scientific assessments that were released since the administrative record concerning the Endangerment Finding was closed after the EPA’s 2010 Reconsideration Denial:

95 Ibid at 120.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 134 of 403 the IPCC (2012) Special Report on Managing the Risks of Extreme Events and Disasters to Advance Climate Change Adaptation (SREX) and the NRC Report (2011) on Climate Stabilization Targets: Emissions, Concentrations, and Impacts over Decades to Millennia (2011). The EPA has reviewed these assessments and they are briefly characterized here: Special Report on Managing the Risks of Extreme Events and Disasters to Advance Climate Change Adaptation (SREX), Intergovernmental Panel on Climate Change, 2012. The IPCC SREX assessment states that, “A changing climate leads to changes in the frequency, intensity, spatial extent, duration, and timing of extreme weather and climate events, and can result in unprecedented extreme weather and climate events.” The SREX documents observational evidence of changes in some of the weather and climate extremes that have occurred globally since 1950. The SREX assessment also provides evidence regarding the attribution of some of these changes to elevated concentrations of GHGs, including warming of extreme daily temperatures, intensification of extreme precipitation events, and rising extreme coastal high water due to increases in sea level. Further The assessment notes that F further increases in some extreme weather and climate events are projected over the 21st century. The assessments Combined also conclude that, combined with increasing vulnerability and exposure of populations and assets, changes in extreme weather and climate events have consequences for disaster risk, with particular impacts on the water, agriculture and food security, and health sectors. Report on Climate Stabilization Targets: Emissions, Concentrations, and Impacts over Decades to Millennia , National Research Council, 2011. The NRC Climate Stabilization Targets assessment states that, “Emissions of carbon dioxide from the burning of fossil fuels have ushered in a new epoch where human activities will largely determine the evolution of Earth’s climate. Because carbon dioxide in the atmosphere is long lived, it can effectively lock Earth and future generations into a range of impacts, some of which could become very Comment [A52]: Acronym for this assessment?***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 135 of 403

severe.” The assessment addresses the fact that emissions of carbon dioxide will alter the composition of the atmosphere, and therefore the climate, for thousands of years and attempts to quantify the implications of stabilizing GHG concentrations at different levels. The report also estimates a number of specific climate change impacts, finding warming could lead to increases in heavy rainfall and decreases in crop yields and Arctic sea ice extent, along with other important changes in precipitation and stream flow. For an increase in global average temperature of 1 to 2 oC above pre-industrial levels, the assessment found that the area burnt by wildfires in western North America will likely more than double and coral bleaching and erosion will increase due both to warming and ocean acidification; an increase of 3 oC will lead to a sea level rise of 1.6 to 3.3 feet by 2100; and with an increase of 4 oC, the average summer in the United States would be as warm as the warmest summers of the past century. The assessment notes that although many important aspects of climate change are difficult to quantify, the risk of adverse impacts is likely to increase with increasing temperature, and the risk of dangerous surprises can be expected to increase with the duration and magnitude of the warming. A number of other National Academy assessments regarding climate have also been released recently. The EPA has reviewed these assessments, and finds that the improved understanding of the climate system resulting from the two assessments described

above and the other National Academy assessments strengthens the case that GHGs are endangering public health and welfare. Perhaps the most dramatic change relative to the prior assessments is that, where the previous 2007 IPCC AR4 assessment projected a rise in global sea level of between 7 and 23 inches by the end of the century relative to 1990 (with an acknowledgment that inclusion of ice sheet processes that were Comment [A53]: Add cites?***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 136 of 403 poorly understood would likely increase those projections), three new NRC assessments (Climate Stabilization Targets, National Security Implications for U.S. Naval Forces in 2011, and Sea Level Rise for the Coasts of California, Oregon, and Washington: Past, Present, and Future in 2012) have provided estimates of projected sea level rise that are twice as large or more. While the three NRC assessments continue to recognize and characterize the uncertainty inherent in accounting for ice sheet processes, these revised estimates strongly support and strengthen the existing finding that GHGs are reasonably anticipated to endanger human health and welfare. Other key findings of the recent assessments are described briefly below:

The Sea Level Rise for the Coasts of California, Oregon, and Washington: Past, Present, and Future (2012) assessment notes that observations have shown that sea level rise on the West Coast has risen south of Cape Mendocino over the past century but dropped north of that point during that time due to tectonic uplift and other factors in Oregon and Washington. However, the assessment projects a global sea level rise of 1.6 to 4.6 feet by 2100, which is sufficient to lead to rising relative sea level even in the northern states. The National Security Implications of Climate Change for U.S. Naval Forces also considers potential impacts of sea level rise, using a range of 1.3 to 6.6 feet by 2100. This assessment also suggests preparing for increased needs for humanitarian aid, responses to climate change in geopolitical hotspots including possible mass migrations, and addressing changing security needs in the Arctic as sea ice retreats. The Climate and Social Stress: Implications for Security Analysis (2012) assessment found that it would be “prudent for security analysts to expect climate surprises in the coming decade . . . and for them to become progressively more serious and more frequent thereafter[.]” Understanding***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 137 of 403 Earth’s Deep Past: Lessons for Our Climate Future (2011) examines the period of Earth’s history prior to the formation of the Antarctic and Greenland Ice Sheets because CO 2 concentrations by the end of the century will have exceeded levels seen in the 30 million years since that time. The assessment discusses the possibility that analogous paleoclimate states might suggest higher climate sensitivity, less well regulated tropical surface temperatures, higher sea level rise, more anoxic oceans,and more potential for non-linear events such as the PaleoEocene Thermal Maximum than previously estimated. The assessment notes that three or four out of the five major coral reef crises of the past 500 million years were probably driven by acidification and warming caused by GHG increases similar to the changes expected over the next hundred years. The assessment states that “the magnitude and rate of the present greenhouse gas increase place the climate system in what could be one of the most severe increases in radiative forcing of the global climate system in Earth history.” Similarly, the Ocean Acidification: A National Strategy to Meet the Challenges of a Changing Ocean (2010) assessment found that “[t]he chemistry of the ocean is changing at an unprecedented rate and magnitude due to anthropogenic carbon dioxide emissions; the rate of change exceeds any known to have occurred for at least the past hundreds of thousands of years.” The assessment notes that the full range of consequences is still unknown, but the risks “threaten coral reefs, fisheries, protected species, and other natural resources of value to society.”

Several commenters on the April 2012 proposed rule argue that the Endangerment Finding should be reconsidered or overturned based on those commenters’ reviews of specific climate science literature, particularly newer publications that have appeared since the EPA’s 2010 Denial of Petitions. Some commenters have presented their own compilations of individual studies as support for their assertions that climate change will have beneficial effects in many cases and that climate impacts***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 138 of 403

will not be as severe or adverse as the EPA and assessments like the USGCRP (2009) report have stated. These commenters conclude that U.S. society will continue to easily adapt to climate change and that climate change therefore does not pose a threat

to human health and welfare.

The EPA has reviewed the information submitted and finds that, the fundamental issues raised in the comments that critique the scientific justification for the rule have been addressed by either the EPA’s 11-volume response to comments for the 2009 Endangerment Finding, the EPA’s responses to all issues raised by Petitioners for the reconsideration of the 2009 Endangerment Finding, or the D.C. Circuit Court in its 2012 decision to uphold the EPA’s 2009 Endangerment Finding. The EPA has nonetheless carefully reviewed these comments and finds again that comments do not change the various conclusions or judgments that the EPA would draw based on the assessment reports relied upon in the recent 2009 Finding. These comments often highlight uncertainty regarding climate science as an argument for reconsideration. However, uncertainty was explicitly recognized in the 2009 Endangerment Finding: “The Administrator acknowledges that some aspects of climate change science and the projected impacts are more***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 139 of 403 certain than others”, 96 and the decision to find endangerment was made with full recognition of the uncertainty involved. In addition, the D.C. Circuit Court decision noted that, “the existence of some uncertainty does not, without more, warrant invalidation of an endangerment finding.” 97 In short, these recent publications submitted by commenters, and any new issues that are extracted from them, do not undermine either the significant body of scientific evidence that has accumulated over the years or the conclusions presented in the substantial peer-reviewed assessments of the USGCRP, NRC, and IPCC. Regarding the contentions that the U.S. will adapt to climate change impacts and that therefore climate change impacts pose no threat, the EPA stated in the 2009 Endangerment Finding, “Risk reduction through adaptation and GHG mitigation measures is of course a strong focal area of scientists and policy makers, including the EPA; however, the EPA considers adaptation and mitigation to be potential responses to endangerment, and as such has determined that they are outside the scope of the endangerment analysis.” 98 The DC Circuit Court upheld this position, ruling that “These contentions [that the U.S. can

96 74 FR 66524. 97 Coalition for Responsible Regulation, Inc. v. EPA , 684 F.3d 121 (D.C. Cir. 2012). 98 74 FR 66512 (emphasis added).***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 140 of 403 adapt] are foreclosed by the language of the statute and the Supreme Court's decision in Massachusetts v. EPA” because “predicting society’s adaptive response to the dangers or harms caused by climate change” does not inform the “scientific judgment” that the EPA is required to take regarding Endangerment. 99 Some commenters raise issues regarding the EPA Inspector General’s report, Procedural Review of EPA’s Greenhouse Gases Endangerment Finding Data Quality Processes . These commenters mischaracterize the report’s scope and conclusions and, thus, vastly overstate the significance of the Inspector General’s procedural recommendations. Ultimately, nothing in the Inspector General report questions the validity of the EPA’s Endangerment Finding because that report did not evaluate the scientific basis of the Endangerment Finding. Rather, the Inspector General offers recommendations for clarifying and standardizing internal procedures for documenting data quality and peer review processes when referencing existing peer reviewed science in the EPA actions. Unrelated to the endangerment finding and its validation by the Circuit Court, the EPA has made progress towards implementing the OIG recommendations.

99 984 F.3d at 117.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 141 of 403 One commenter submitted a number of emails from the period 1999 to 2009 that were obtained from a University of East Anglia server in 2009 and publicly released in 2011. After reviewing these emails, the EPA finds that they raise no issues that were not previously raised by Petitioners in regard to an earlier group of emails from the same incident, released in 2009. The commenter makes unsubstantiated assumptions and subjective assertions regarding what the e-mails purport to show about the state of climate change science; this provides inadequate evidence to challenge the voluminous and well documented body of

science that is the technical foundation of the Administrator’s Endangerment Finding. A number of comments were also submitted in support of the Endangerment Finding and/or providing further evidence that climate change is a threat to human health and welfare. A number

of individual studies were submitted and a number of observed or projected climate changes of local importance or concern to commenters were documented. Again, the EPA places lesser weight on individual studies than on the major scientific assessments. Local observed changes can be of great concern to individuals

and communities but must be assessed in the context of the broader science, as it is more difficult to draw robust***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 142 of 403 conclusions regarding climate change over short time scales and in small geographic regions. **V. Rationale for Applicability Requirements** A. Applicability requirements - original proposal and comments The original proposal was designed to apply to newintermediate and baseload EGUs, specifically, 1) fossil fuelfired boiler/steam turbines and IGCC EGUs subject to subpart Da for criteria pollutant emissions, and 2) combined cycle EGUs subject to subpart KKKK for criteria pollutant emissions. The original proposal explicitly did not apply to simple cycle turbines because we concluded that they were operated infrequently and therefore only contributed small amounts to total GHG emissions. (For convenience, we occasionally refer to this explicit statement that the proposed NSPS did not apply to a type of source as an exclusion). We received comments that supported the simple cycle exclusion and others that opposed it. Commenters in support stated that a new simple cycle power plant serves a different purpose than a new combined cycle plant and that economics will drive the use of combined cycle facilities over simple cycle plants. They also stated that the proposed standard is not achievable by, and therefore is not BSER for, simple cycle turbines. Commenters opposing the exclusion stated that it***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 143 of 403 creates an opportunity to evade the standard and could thereby increase GHG emissions. According to these commenters, any applicability distinctions should be based on utilization and function rather than purpose or technology. After considering these comments, we are proposing a different approach to the applicability provisions. B. Applicability requirements – today’s proposal In today’s rulemaking, we propose that applicability should be based on electric sales alone, so that the proposed standards of performance apply to a facility if the facility sells more than 1/3 of its potential electric output and more than 219,000 MWh net electric output to the grid. (We refer to a facility’s sale of more than one-third of its potential electric output as the 33 percent sales criterion, and we refer to the amount of potential electric output sold as the capacity factor.) This proposed definition does not explicitly exclude simple cycle combustion turbines, but as a practical matter, it would exclude most of them because the vast majority of simple cycle turbines sell less than 1/3 of their potential electric output. For combustion turbines that sell more than 1/3 of their potential electric output to the grid, we have concluded there are less expensive and lower emitting technologies that could be constructed consistent with today’s proposed standards. Comment [A54]: We would suggest adding a more clear justification for why EPA thinks this exclusion is needed. The description here seems to focus on why the exclusion was structured the way that it is versus why it is appropriate or what it is trying to achieve.

Comment [A55]: Per year?

Comment [A56]: Please add a description that indicates what, generally, the other 2/3 of electric output goes towards.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 144 of 403 Although, as noted, today’s proposal does not explicitly exclude simple cycle combustion turbines, we solicit comment on whether to provide an explicit exclusion. We are proposing to apply the 33 percent sales criterion on a rolling three year basis instead of an annual basis for stationary combustion turbines for multiple reasons. First, extending the period to three years would permit facilities intended to generally operate at low capacity factors (e.g. simple cycle turbines that sell less than 1/3 of their potential electric output) to provide system capacity and operate at high capacity factors during individual years with abnormally high electric demand. Second, only 0.2 percent of existing simple cycle turbines had a three-year average capacity factor of greater than 33 percent between 2000 and 2012. Therefore, as noted, from a practical standpoint, few new simple cycle turbines be subjected to the standards of performance in this rulemaking. In addition, according to the AEO 2013 cost and performance characteristics for new generation technologies, advanced combined cycle facilities have a lower cost of electricity than advanced simple cycle turbine facilities above approximately a 20 percent capacity factor. Therefore, the use of a combined cycle technology would be BSER for higher capacity factor***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 145 of 403 stationary combustion turbines. In addition, the 2013 AEO cost and performance characteristics for new generation technologies include costs for a conventional combined cycle facility. Advanced combined cycle facilities do not have a lower cost of electricity than conventional combined cycle facilities until above approximately a 40 percent capacity factor. Between approximately 20 to 40 percent capacity factors, conventional combined cycle facilities offer the lowest cost of electricity, and below approximately 20 percent capacity factors simple cycle turbines offer the lowest cost of electricity. A capacity factor exemption at 40 percent would allow combined cycle facilities built for low capacity factors to compete simple cycle turbines because neither would be subject to the NSPS requirements. Based on these cost considerations, we are specifically requesting comment on a range of 20 to 40 percent of potential electric output sales on a three-year basis for the capacity factor exemption. The lower range is consistent with generating the lowest cost of electricity for advanced combined cycle turbines, and based on historical capacity factors would impact the operation of only approximately two percent of simple cycle turbines. The upper range would be more consistent with the annual operational hour limitations in many simple cycle permits and would provide significant operational flexibility.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 146 of 403 We are also requesting comments on whether applicability for stationary combustion turbines should be defined on a single calendar year basis, similar to the subpart Da applicability provisions, instead of a three-year basis. With a single year basis, we are considering an applicability level of 40 (instead of 33 percent) percent sales. Only 0.4 percent of existing simple cycle turbines had an annual capacity factor of greater than 40 percent between 2000 and 2012. Assuming the average hourly output of a simple cycle turbine is 80 percent of the maximum rated output, a simple cycle turbine could operate up to 4,400 hours annually before exceeding the capacity factor threshold. This is consistent with the operation hour limitation in many permits. Therefore, with this 40 percent sales criterion on a single-year basis, as a practical matter, few new simple cycle turbines would be subject to the proposed standards of performance. We are specifically requesting comment on a range of 1/3 to 2/5 of potential electric output annual sales. The lower range would be consistent with how an EGU is currently defined in the EPA rules, and would mean that the proposed standards of performance would impact to approximately one percent of new simple cycle turbines. We are also proposing a different definition of potential electric output from the current definition in subpart Da. The***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 147 of 403 existing definition is based on the design heat input capacity and assumes a 33 percent net electric efficiency, regardless of the actual efficiency of the facility. This could potentially have a negative impact on more efficient facilities. For example, a 33 percent efficient 100 MW facility would have a potential electric output of 876,000 MWh and a 40 percent efficient 100 MW facility would have a potential electric output of only 723,000 MWh. This could potentially encourage the construction of less efficient facilities, since they could have a higher actual capacity factor than a more efficient unit, while still not being an EGU subject to a CO 2 standard. Therefore, we are proposing a definition of potential electric output that allows the source the option of calculating its potential electric output on the basis of its actual design electric output efficiency on a net output basis, as an alternative to the default 33 percent value. The April 2012 proposal would have applied to facilities that primarily burn non-fossil fuels but also co-fire a fossil fuel. We have concluded that it is not appropriate to subject these facilities to the standards in today’s proposal. Therefore, we are proposing to limit the applicability of the standard to facilities where the heat input is comprised of more than 10.0 percent fossil fuel on a three-year rolling average basis. This Comment [A57]: EPA should add more explanation of its rational for this determination.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 148 of 403 approach is similar to that of the Mercury and Air Toxics Standards. To simplify determining applicability with the CO 2 standard, we also request comment on whether the applicability

for facilities that co-fire non-fossil fuels should be made on an annual average basis, instead of a three-year rolling average

basis. In the original proposal, we requested comment on the applicability of the GHG NSPS to combined heat and power (CHP) facilities and if it should be changed from how it is currently determined in subpart Da. We have concluded that if CHP facilities meet the general applicability criteria they should be subject to the same requirements as electric-only generators. However, one potential issue that we have identified is inequitable applicability to third-party CHP developers compared to CHP facilities owned by the facility using the thermal output from the CHP facility. Third-party CHP developers would not have been able to benefit from the “minus purchased power on a calendar year basis” in the definition of net electric output when determining applicability since the thermal host(s) are not part of the same affected facility. We are therefore proposing to add “of the thermal host facility or facilities” to the definition of net-electric output for qualifying CHP facilities.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 149 of 403 This would make applicability consistent for both facility-owned CHP and third-party-owned CHP. This proposal includes adding “any integrated device that provides electricity or useful thermal output to either the boiler/stationary combustion turbine or to power auxiliary equipment” in the definition of a steam electric generating unit, IGCC, and stationary combustion turbine in subparts Da and KKKK respectively. The rationale behind including integrated equipment is to avoid circumvention of the requirements by having a boiler not subject to the standard supplying useful energy input (e.g., for amine regeneration in a CCS system) without accounting for the GHG emissions, and to provide additional compliance flexibility. Even without this specific language, the original 1979 steam electric generating unit definition in subpart Da allows the use of solar thermal for feedwater heating as an approach to integrating non-emitting generation to reduce environmental impact and lower the overall emissions rate. The current definition expands the flexibility to include combustion turbines, fuel cells, or other combustion technology for reheating or preheating boiler feedwater, preheating combustion air, producing steam for use in the steam turbine or to power the boiler feedpumps, or using the exhaust directly in the boiler to generate steam. This in theory could***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 150 of 403 lower generation costs as well as lower the GHG emissions rate for an EGU. For example, using heat from integrated equipment to

reheat boiler feedwater in a coal-fired EGU would minimize the

steam otherwise extracted from the steam turbine used for the feedwater reheating process. This would decrease the size of the coal-fired boiler by approximately 1/4 for the same overall electric output, reducing the initial capital required to construct the new coal-fired portion of the EGU. Potential

emission rate reductions are similar. While IGCC and NGCC do not extract the same levels of steam for feedwater heating requirements, multiple projects exist where solar thermal is integrated into the facility to preheat the feedwater and increase the output from the steam turbine relative to an NGCC facility without integrated solar thermal. Our understanding is that one of the primary benefits of this approach is decreased incremental cost of the solar thermal generated electricity due to the ability to use equipment (e.g., HRSG, steam turbine, condenser, etc.) already included at the NGCC facility. C. Codification in the Code of Federal Regulations In the original proposal, the EPA proposed to create within 40 CFR part 60 a new subpart that would include GHG emission regulatory requirements for electric utility steam generating units (i.e., boilers and IGCC units), whose conventional***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 151 of 403 pollutant regulatory requirements are codified under subpart Da; as well as stationary combustion turbines that generate electricity for sale and meet certain size and operational criteria, conventional pollutant regulatory requirements are codified under subpart KKKK. The EPA proposed to number this newly created subpart as subpart TTTT. The EPA explained that combining the GHG regulatory requirements for those sources in TTTT was appropriate because the EPA was establishing the same limit for all those sources based on the same BSER, which was

NGCC. In today’s rulemaking, we propose different standards,based on different determinations of BSER, for (1) fossil fuelfired utility boilers and IGCC units, and (2) natural gas-fired stationary combustion turbines. In this manner, in accordance with CAA §111(b)(2), we are “distinguish[ing] among classes, types, and sizes within [the category of electric generating plants] of new sources for the purpose of establishing ... [the new source performance] standards.” As noted, to avoid confusion, we are codifying the new GHG regulatory requirements in the same subparts – Da and KKKK – that include the standards for conventional pollutants from those sources. Note that this codification does not increase the stringency of the NSPS requirements for criteria air pollutant emissions from those***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 152 of 403 sources, and thus does not affect the continued codification of those requirements in subparts Da and KKKK, as the case may be. **VI. Legal Requirements for Establishing Emission Standards**

A. Overview In this section, we describe the principal legal requirement for the standards of performance under CAA §111 that we propose in this rulemaking, which is that the standards must consist of emission limits that are based on the “best system of emission reduction ... adequately demonstrated,” taking into account cost and other factors. In this manner, CAA §111 provides that the EPA’s central task is to identify the BSER. The D.C. Circuit has handed down case law, which we review in detail, that interprets this CAA provision, including its component elements. The Court’s interpretation indicates the technical, economic, and energy-related factors that are relevant for determining the BSER, and provides the framework for analyzing those factors. According to the D.C. Circuit, EPA determines the best demonstrated system based on the following key considerations, among others:

 The system of emission reduction must be technically

feasible.

 EPA must consider the amount of emissions reductions that***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 153 of 403 the system would generate.

 The costs of the system must be reasonable. EPA may consider the costs on the source level, the industry-wide level, and, at least in the case of the power sector, on

the national level in terms of the overall costs of electricity and the impact on the national economy over

time.

 EPA must also consider that CAA §111 is designed to promote the development and implementation of technology.

Other considerations are also important, including that EPA must also consider energy impacts, and, as with costs, may

consider them on the source level and on the nationwide structure of the power sector over time. Importantly, EPA has discretion to weigh these various considerations, may determine that some merit greater weight than others, and may vary the weighting depending on the source category. B. CAA requirements and Court interpretation 1. Clean Air Act Requirements The EPA’s basis for proposing that partial capture CCS is the BSER for new fossil fuel-fired utility boilers and IGCC units, and that NGCC is the BSER for natural gas-fired stationary combustion turbines, is rooted in the provisions of Comment [A58]: This focuses on BSER instead of the standards of performance, but suggest that EPA consider referencing standards of performance here, especially since the next paragraph starts with that discussion. Or, consider stating that the basis of both the standards of performance and BSER are rooted in CAA 111 and caselaw.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 154 of 403 CAA §111 requirements, as interpreted by the United States Court of Appeals for the D.C. Circuit (“D.C. Circuit” or “Court”), which is the federal Court of Appeals with jurisdiction over the EPA’s CAA rulemaking. As the first step towards establishing standards of performance, the EPA “shall publish ... a list of categories of stationary sources ... [that] cause[], or contribute[] significantly to, air pollution which may reasonably be anticipated to endanger public health or welfare.” §111(b)(1)(A). Following that listing, the EPA “shall publish proposed regulations, establishing federal standards of performance for new sources within such category” and then “promulgate ... such standards” within a year after proposal. §111(b)(1)(B). The EPA “may distinguish among classes, types, and sizes within categories of new sources for the purpose of establishing such standards.” §111(b)(2). The term “standard of performance” is defined to “mean[] a standard for emissions of air pollutants which reflects the degree of emission limitation achievable through the application of the best system of emission reduction which (taking into account the cost of achieving such reduction and any nonair quality health and environmental impact and energy requirements) the Administrator determines has been adequately demonstrated.” §111(a)(1).***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 155 of 403 2. Court interpretation For present purposes, the key §111 provisions are the definition of “standard of performance,” under CAA §111(a)(1), and, in particular, the “best system of emission reduction which (taking into account ... cost ... nonair quality health and environmental impact and energy requirements) ... has been adequately demonstrated.” The D.C. Circuit has reviewed rulemakings under §111 on numerous occasions during the past 40 years, handing down decisions dated from 1973 to 2011, 100 through which the Court has developed a body of case law that interprets the term “standard of performance.” These interpretations are of central importance to the EPA’s justification for the standards of performance in the present rulemaking. At the outset, it should be noted that Congress first included the definition of “standard of performance” when enacting CAA §111 in the 1970 Clean Air Act Amendments (CAAA), and then amended it in the 1977 CAAA, and then amended it again in the 1990 CAAA, generally repealing the amendments in the 1977 CAAA and, therefore, reverting to the version as it read after

100 Portland Cement Ass’n v. Ruckelshaus , 486 F.2d 375 (D.C. Cir. 1973); Essex Chemical Corp. v. Ruckelshaus , 486 F.2d 427, (D.C. Cir. 1973); Portland Cement Ass’n v. EPA , 665 F.3d 177 (D.C. Cir. 2011).***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 156 of 403 the 1970 CAAA. The legislative history for the 1970 and 1977 CAAAs explained various aspects of the definition as it read at those times. Moreover, the various decisions of the D.C. Circuit interpreted the definition that was applicable to the rulemakings before the Court. Notwithstanding the amendments to the definition, the D.C. Circuit’s interpretations discussed below remain applicable to the current definition. 101

101 In the 1970 CAAA, Congress defined “standard of performance,” under §111(a)(1), as— a standard for emissions of air pollutants which reflects the degree of emission limitation achievable through the application of the best system of emission reduction which (taking into account the cost of achieving such reduction) the Administrator determines has been adequately demonstrated. In the 1977 CAAA, Congress revised the definition to distinguish among different types of sources, and to require that for fossil fuel-fired sources, the standard (i) be based on, in lieu of the “best system of emission reduction ... adequately demonstrated,” the “best technological system of continuous emission reduction ... adequately demonstrated;” and (ii) require a percentage reduction in emissions. In addition, in the 1977 CAAA, Congress expanded the parenthetical requirement that the Administrator consider the cost of achieving the reduction to also require the Administrator to consider “any nonair quality health and environment impact and energy requirements.” In the 1990 CAAA, Congress again revised the definition, this time repealing the requirements that the standard of performance be based on the best technological system and achieve a percentage reduction in emissions, and replacing those provisions with the terms used in the 1970 CAAA version of §111(a)(1) that the standard of performance be based on the “best system of emission reduction ... adequately demonstrated.” This 1990 CAAA version is the current definition, which is***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 157 of 403 3. Overview of interpretation By its terms, the definition of “standard of performance” under CAA § 111(a)(1) provides that the emission limit that the EPA promulgates must be “achievable” and must be based on a system of emission reduction – generally, but not required to be always, a technological control -- that the EPA determines to be the “best system” that is “adequately demonstrated,” “taking into account ... cost ... nonair quality health and environmental impact and energy requirements.” The D.C. Circuit has stated that in determining the “best” system, the EPA must also take into account “the amount of air pollution” 102 and may take into account “technological innovation.” 103 As discussed below, the D.C. Circuit has elaborated on the criteria and process for determining whether a standard is “achievable,” based on an “adequately demonstrated” technology or system. In addition, the Court has identified limits on the costs and other factors that are acceptable for the technology or system to qualify as the “best.” The Court has also held that the EPA may consider the costs and other factors on a regional

applicable at present. Even so, because parts of the definition as it read under the 1977 CAAA were retained in the 1990 CAAA, the explanation in the 1977 CAAA legislative history, and the interpretation in the case law, of those parts of the definition remain relevant to the definition as it reads today.

102 See Sierra Club v. Costle , 657 F.2d 298, 326 (D.C. Cir. 1981).

103 See Sierra Club v. Costle , 657 F.2d at 347.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 158 of 403 or national level (e.g., the EPA may consider impacts on the national economy and the affected industry as a whole) and over time, and not just on a plant-specific level at the time of the rulemaking. 104 In addition, the Court has emphasized that the EPA has a great deal of discretion in weighing the various factors to determine the “best system.” 105 Moreover, the Court has stated that in considering the various factors and determining the “best system,” the EPA must be mindful of the purposes of §111, and the Court has identified those purposes as “not giv[ing] a competitive advantage to one State over another in attracting industry[,]... “reducing emissions as much as practicable[,]”... “forc[ing] the installation of all the control technology that will ever be necessary on new plants at the time of construction[,]...” and “forc[ing] the development of improved technology.” 106 Finally, based on cases the D.C. Circuit has handed down under related provisions of the CAA and the EPA’s regulatory precedent under §111, the EPA may promulgate a standard of performance for a particular category of sources even if not every type of new source in the category would be

104 See Sierra Club v. Costle, 657 F.2d at 330. 105 See Lignite Energy Council v. EPA, 198 F.3d 930, 933 (D.C. Cir. 1999). 106 Sierra Club v. Costle , 657 F.2d at 325 & n.83 (quoting 44 Fed.Reg. 33,580, 33,581/3-33,582/1).***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 159 of 403

able to achieve that standard. 107 We next discuss in more detail each of these components of the interpretation of “standard of performance.” C. Technical feasibility The D.C. Circuit’s first decision under §111, Portland

Cement Ass’n v. Ruckelshaus , 486 F.2d 375, 391 (D.C. Cir. 1973), concerned whether EPA’s standard of performance for the cement industry met the requirement to be “achievable,” which, in turn, depended on whether the technology on which EPA based the standard was “adequately demonstrated.” 108 In this case, the Court interpreted these provisions to require that the technology must be technically feasible for the source category, and established criteria for determining technical feasibility. The Court explained that a standard of performance is “achievable” if a technology can reasonably be projected to be available to new sources at the time they are constructed that will allow them to meet the standard. Specifically, the D.C. Circuit explained: Section 111 looks toward what may fairly be projected for the regulated future, rather than the state of the art at present, since it is addressed to standards for new plants....- It is the “achievability” of the proposed standard that is in

107 See, e.g., International Harvester Co. v. EPA , 478 F.2d 615, 640 (D.C. Cir. 1973). 108 486 F.2d at 390.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 160 of 403

issue.... The Senate Report made clear that it did not intend that the technology “must be in actual routine use somewhere.” The essential question was rather whether the technology would be available for installation in new plants.... The Administrator may make a projection based on existing technology, though that projection is subject to the restraints of reasonableness and cannot be based on “crystal ball” inquiry. 109 In subsequent cases, the D.C. Circuit has consistently

reiterated this formulation of “achievable.” 110

It should be noted that in another of the early cases, Essex Chemical Corp. v. Ruckelshaus , 486 F.2d 427 (D.C. Cir. 1973), the D.C. Circuit upheld a standard of performance as “achievable” on the basis of test data showing that the tested plant emitted less than or at the standard on three occasions and emitted above the standard on 16 occasions, and that, on average, it emitted 15% above the standard on a total of 19

occasions. 111 The fact that the plant had achieved the standard on at least a few occasions, even though the plant had not done so on the great majority of occasions, “adequately demonstrated”

that the standard was “achievable.” D. Factors to consider in determining the “best system”

109 Portland Cement Ass’n v. Ruckelshaus , 486 F.2d 375, 391 (D.C. Cir. 1973) (citations omitted). 110 See, e.g., National Asphalt Pavement Ass’n v. Train , 539 F.2d 775, 785 (D.C. Cir. 1976); Lignite Energy Council v. EPA, 109 F / /

. 3d 930, 934 (D.C. Cir. 1999). 111 Essex Chemical Corp. v. Ruckelshaus , 486 F.2d at 437 & n. 27. Formatted: Highlight Formatted: Highlight***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 161 of 403

1. Amount of emissions reductions Although the definition of “standard of performance” does not by its terms identify the amount of emissions from the category of sources and the amount of emission reductions achieved as factors the EPA must consider in determining the “best system of emission reduction,” the D.C. Circuit has stated that the EPA must do so. See Sierra Club v. Costle, 657 F.2d 298, 326 (D.C. Cir. 1981) (“we can think of no sensible interpretation of the statutory words “best ... system” which would not incorporate the amount of air pollution as a relevant factor to be weighed when determining the optimal standard for controlling ... emissions”). 112

2. Costs In several cases, the D.C. Circuit has elaborated on the cost factor that the EPA is required to consider under CAA §111(a)(1), and has identified limits to how costly a control technology may be before it no longer qualifies as the “best system of emission reduction ... adequately demonstrated.” As a

112 Sierra Club v. Costle, 657 F.2d 298 (D.C. Cir. 1981) was governed by the 1977 CAAA version of the definition of “standard of performance,” which revised the phrase “best system” to read, “best technological system.” The 1990 CAAA deleted “technological,” and thereby returned the phrase to how it read under the 1970 CAAA. The Sierra Club v. Costle ’s interpretation of this phrase to require consideration of the amount of air emissions remains valid for the phrase “best system.”***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 162 of 403 related matter, although no D.C. Circuit case addresses how to account for revenue generated from the byproducts of pollution control, it is logical and a reasonable interpretation of the statute that the costs of the control technology should be offset by any revenues from the sale of pollutants or pollution control byproducts associated with those controls. Clearly, such a sale would offset regulatory costs and so must be included to accurately assess the costs of the standard.

a. Criteria for costs (i) Formulation In Essex Chemical Corp. v. Ruckelshaus , 486 F.2d 427, 433 (D.C. Cir. 1973), the D.C. Circuit stated that to be “adequately demonstrated,” the system must be “reasonably reliable, reasonably efficient, and ... reasonably expected to serve the interests of pollution control without becoming exorbitantly costly in an economic or environmental way.” The Court has reiterated this limit in subsequent case law, including Lignite Energy Council v. EPA , 198 F.3d 930, 933 (D.C. Cir. 1999), in

which it stated: “EPA's choice will be sustained unless the environmental or economic costs of using the technology are

exorbitant.” In Portland Cement Ass’n v. EPA , 513 F.2d 506, 508 (D.C. Cir. 1975), the Court elaborated by explaining that the inquiry is whether the costs of the standard are “greater than Comment [A59]: Has this been done in any other NSPS context that could be referenced here?***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 163 of 403 the industry could bear and survive.” In Sierra Club v. Costle, 657 F.2d 298, 343 (D.C. Cir. 1981), the Court provided a substantially similar formulation of

the cost standard when it held: “EPA concluded that the Electric

Utilities' forecasted cost was not excessive and did not make the cost of compliance with the standard unreasonable. This is a judgment call with which we are not inclined to quarrel.” We

believe that these various formulations of the cost standard – “exorbitant,” “greater than the industry could bear and survive,” “excessive,” and “unreasonable” – are synonymous; the D.C. Circuit has made no attempt to distinguish among them. For convenience, in this rulemaking, we will use the “unreasonable” formulation, so that a control technology cannot be considered the “best system of emission reduction ... adequately

demonstrated” if its costs are “unreasonable.” (ii) Examples In the case law under CAA §111, the D.C. Circuit has never invalidated a standard of performance on grounds that it was too costly. In several cases, the Court upheld standards that entailed high costs. In Portland Cement Association v.

Ruckelshaus , 486 F.2d 375 (D.C. Cir. 1973), the Court considered a standard of performance that the EPA promulgated for particulate matter emissions from new and modified Portland***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 164 of 403 cement plants. According to the Court, the cost for the control technologies that a new facility would need to install to meet the standard was about 12 percent of the capital investment for the total facility, and annual operating costs for the control equipment would be 5-7 percent of the total plant operating costs. The Court found that these costs “could be passed on without substantially affecting competition” because the demand for the product was not “highly elastic with regard to price and would not be very sensitive to small price changes.” The Court held that the EPA gave appropriate consideration to the “economic costs to the industry.” 113

In Sierra Club v. Costle , 657 F.2d 298 (D.C. Cir. 1981), the D.C. Circuit upheld a standard of performance imposing costly controls on SO 2 emissions from coal-fired power plants.

The Court noted: The importance of the challenged standards arises not only from the magnitude of the environmental and health interests involved, but also from the critical implications the new pollution controls have for the economy at the local and national levels.   Coal is the dominant fuel used for generating electricity in the United States .... In 1976 power plant emissions accounted for 64 percent of the total estimated sulfur dioxide emissions and 24 percent of the total estimated particulate matter emissions in the entire country.

113 Portland Cement Association v. Ruckelshaus , 486 F.2d at 387- 88. Comment [A60]: Is the case the same for EGUs? Add a FN to explain relevance.** *E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 165 of 403 EPA's revised NSPS are designed to curtail these emissions. EPA predicts that the new standards would reduce national sulfur dioxide emissions from new plants by 50 percent and national particulate matter emissions by 70 percent by 1995. The cost of the new controls, however, is substantial. EPA estimates that utilities will have to spend tens of billions of dollars by 1995 on pollution control under the new NSPS. Consumers will ultimately bear these costs, both directly in the form of residential utility bills, and indirectly in the form of higher consumer prices due to increased energy costs. 114

b. Revenue enhancements In determining , the costs of pollution control technology, it is reasonable to take into account any revenues generated by the sale of any by-products of the control process. Many types of pollution control technology generate byproducts that must be disposed, and the costs of that disposal are considered part of the costs of the control technology. For example, CCS generates

a stream of CO 2 that must be disposed of through sequestration. In some instances, however, the by-products of pollution control have marketable value. In these cases, revenues from selling the by-products would defray the costs of pollution

control. 115 For example, in a recent rulemaking under the CAA regional haze program that entailed determining the “best available retrofit technology” (BART) for power plants, revenue

114 Sierra Club v. Costle , 657 F.2d at 313 (citations omitted) (emphasis added). 115 76 Fed. Reg. 58,570, 58,603/1-2 (September 21, 2011).***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 166 of 403 from fly ash generated during boiler combustion and sold for use in concrete production factored into the State’s selection of BART). 116

3. Expanded use and development of technology

In Sierra Club v. Costle , the Court made clear that technological innovation was grounded in the terms of section 111 itself, and therefore should be considered one of the factors to be considered in determining the “best system of

emission reduction:” Our interpretation of section 111(a) is that the mandated balancing of cost, energy, and nonair quality health and environmental factors embraces consideration of technological innovation as part of that balance. The statutory factors which EPA must weigh are broadly defined and include within their ambit subfactors such as technological innovation. 117 As discussed below, CAA §111 standards can promote technological innovation through: (i) the expanded use of the technology that is considered to be the best demonstrated technology; (ii) the further development of the best

116 Similarly, the EPA has taken into account the value of fuel savings in determining the costs of rules that limit emissions from motor vehicles, which limits manufacturers are expected to achieve by reducing the rates of fuel consumption by the vehicles. See, e.g., 77 Fed. Reg. 62,624, 62,628-29; 62,923-27; 62,942-46 (October 15, 2012) (rulemaking setting GHG emissions standards for Light-Duty Vehicles for Model Years 2017-2025).

117 Sierra Club v. Costle , 657 F.2d at 347. Comment [A61]: Add a citation to the State determination in the FN before sentence regarding EPA LDV rule.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 167 of 403 demonstrated technology; and (iii) the development of technology that is emerging, but that is not necessarily on a path to become the best demonstrated technology. E. Nationwide component of factors in determining the “best

system” Another component of the D.C. Circuit’s interpretations of section 111 is that the EPA may consider the various factors it is required to balance on a national or regional level and over time, and not only on a plant-specific level at the time of the rulemaking. 118 As the D.C. Circuit stated in Sierra Club v.

Costle: The language of [the definition of ‘standard of performance’ in] section 111 ... gives EPA authority when determining the best ... system to weigh cost, energy, and environmental impacts in the broadest sense at the national and regional levels and over time as opposed to simply at the plant level in the immediate present. 119 In that case, in upholding the EPA’s variable standard for

SO 2 emissions, the D.C. Circuit justified and elaborated on that interpretation of the definition of “standard of performance;” and then went on to evaluate the EPA’s justification for its rulemaking in light of that interpretation. It is useful to set out these parts of the Court’s opinion at some length in order

118 Sierra Club v. Costle, 657 F.2d at 351. 119 Sierra Club v. Costle , 657 F.2d at 330. Comment [A62]: This last part doesn’t seem to be explained later. Discussion later talks about “the development of technology that is emerging.” Explanation of the “not necessarily on a path to become the best demonstrated technology” part would be helpful.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 168 of 403 to make clear the scope of the factors and the nature of the balancing exercise that the Court held section 111(a)(1)

authorizes the EPA to take.

The Court first recited the terms of the definition of “standard of performance,” as it read following the 1977 CAA

Amendments: The pertinent portion of section 111 reads: A standard of performance shall reflect the degree of emission limitation ... achievable through application of the best ... system of ... emission reduction which (taking into consideration the cost of achieving such emission reduction, any nonair quality health and environmental impact and energy requirements) the Administrator determines has been adequately demonstrated. 120 The Court then stated that these terms could reasonably be

read to authorize the EPA to establish the standard of performance based on environmental, economic, and energy considerations “on the grand scale:” Parsed, section 111 most reasonably seems to require that EPA identify the emission levels that are “achievable” with “adequately demonstrated technology.” After EPA makes this determination, it must exercise its discretion to choose an achievable emission level which represents the best balance of economic, environmental, and energy considerations. It

120 Sierra Club v. Costle , 657 F.2d at 330. Note that the elipses in the quotation of the definition of “standard of performance” in the text indicate the omission of terms repealed by the 1990 CAAA; the Court’s analysis of the meaning of this definition did not turn on those repealed terms, and as a result, the Court’s analysis remains relevant for the current definition of “standard of performance.”***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 169 of 403

follows that to exercise this discretion EPA must examine the effects of technology on the grand scale in order to decide which level of control is best **.** For example, an efficient water intensive technology capable of 95 percent removal efficiency might be “best” in the East where water is plentiful, but environmentally disastrous in the water-scarce West where a different technology, capable of only 80 percent reduction efficiency might be “best.” ... Thestandard is, after all, a national standard with longterm effects. 121

The Court then justified its “reading of ... section 111 as authorizing the EPA to balance long-term national and regional impacts of alternative standards” on the 1977 CAAA legislative history: The Conferees defined the best technology in terms of “long-term growth,” “long-term cost savings,” effects on the “coal market,” including prices and utilization of coal reserves, and “incentives for improved technology.” Indeed, the Reports from both Houses on the Senate and House bills illustrate very clearly that Congress itself was using a long-term lens with a broad focus on future costs, environmental and energy effects of different technological systems when it discussed section 111. 122 The Court then examined the EPA’s justification for the variable standard. The Court quoted at length the EPA’s

121 Sierra Club v. Costle , 657 F.2d at 330 (emphasis added). As noted, after the 1990 CAAA -- which changed the term “best technological system ... of emission reduction ... adequately demonstrated” to “best system ... of emission reduction ... adequately demonstrated” -- the Court’s discussion of “adequately demonstrated technology” should be considered to hold true for adequately demonstrated system of emission reduction.

122 Sierra Club v. Costle , 657 F.2d at 331 (emphasis added) (citations omitted) (citing legislative history).***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 170 of 403 discussion of how it “justified the variable standard in terms of the policies of the Act,” including, in part: The standard reflects a balance in environmental, economic, and energy consideration by being sufficiently stringent to bring about substantial reductions in SO 2 emissions (3 million tons in 1995) yet does so at reasonable costs without significant energy penalties.... By achieving a balanced coal demand within the utility sector and by promoting the development of less expensive SO 2 control technology, the final standard will expand environmentally acceptable energy supplies to existing power plants and industrial sources. By substantially reducing SO 2 emissions, the standard will enhance the potential for long term economic growth at both the national and regional levels. 123

The D.C. Circuit then held that it found this explanation to be

reasonable. 124 F. Overall purposes The D.C. Circuit, during an extensive discussion of “standard of performance” in the 1981 decision in Sierra Club v.

Costle , identified and explained the purposes of section 111 and upheld a standard in part on grounds that it was consistent with those purposes. 125 Specifically, the D.C. Circuit identified “the essential purposes” of CAA §111 – insofar as relevant for

123 Sierra Club v. Costle , 657 F.2d at 327-28 (quoting 44 Fed. Reg. at 33,583/3 - 33,584/1). 124 Sierra Club v. Costle , 657 F.2d at 337-39. 125 Sierra Club v. Costle, 658 F.2d 298, 338-340 (D.C. Cir. 1981). Comment [A63]: Elaborate this sentence or add another sentence to summarize the point you are trying to make here, which seems to be about EPA balancing factors on a national or regional level and over time (as opposed to about the fact that EPA selected a variable standard). The conclusion needs to be more robust to keep the reader oriented.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 171 of 403 present purposes -- as follows: 126 1. The standards must not give a competitive advantage to one State over another in attracting industry.2. The standards must maximize the potential for longterm economic growth by reducing emissions as much as practicable. This would increase the amount of industrial growth possible within the limits set by the air quality standards. 3. The standards must to the extent practical force the installation of all the control technology that will ever be necessary on new plants at the time of construction when it is cheaper to install, thereby minimizing the need for retrofit in the future when air quality standards begin to set limits to growth. * * * * 6. The standards should be stringent in order to force

126 In Sierra Club v. Costle , the Court noted that during the course of the 1977 CAAA, the House-Senate Conference Committee added the percentage reduction requirement to the text of section 111, and, in the Conference Committee Report, explained that although EPA had the authority to establish a variable standard that reflected varying fuel characteristics, EPA could do so only after “finding that such a [variable standard] does not undermine the basic purposes of [section 111] and the other provisions of the [CAA]....” Sierra Club v. Costle , 657 F.2d at 319 (citing H.R. Rep. No. 95-564, at 130 (1977)(Conf. Rep.), reprinted in 1977 U.S.C.C.A.N. 1077 (1977 Conference Report)). The Court noted that those purposes were set forth in the legislative history, and went on to recite and then apply them. See Sierra Club v. Costle , 657 F.2d at 325, 338-40. The variable standard at issue in that case is not directly relevant to the present rulemaking. Regardless, the purposes of section 111, as described by the Court, remain valid because they were valid under the 1977 CAAA, which, in relevant part, were not revised by the 1990 CAAA. If there is any question about that, then the purposes remain valid because the 1977 House Committee Report grounded them in the 1970 CAAA, see H.R. Rep. No. 95-294, 95th Cong., 1st Sess. 184-86 (1977) (1977 House Comm. Rep.), and the 1990 CAAA changes to the definition of standard of performance had the effect of reinstating the definition as it read under the 1970 CAAA (with one addition, noted below).***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 172 of 403 the development of improved technology. 127

These purposes merit further discussion here. 1. No competitive advantage to any State The first purpose for the standards, as quoted above – “not giv[ing] a competitive advantage to one State over another in attracting industry” – arose from Congress’s concern, expressed during the debates over the 1970 CAAA, that States had at least a short-term economic incentive to attract industry by limiting pollution controls, and that States with cleaner air quality would be positioned to do so. Congress designed section 111 to address that problem by requiring the EPA to establish nationwide emission limitations, which would apply regardless of any State’s air quality, and without giving advantage to any

127 Sierra Club v. Costle , 657 F.2d at 325 & n.83 (quoting 44 Fed. Reg. 33,580, 33,581/3-33,582/1 (EPA summary of the six purposes identified in the 1977 House Committee Report, H.R. Rep. No. 95-294, 95th Cong., 1st Sess. 184-86 (1977)) The Court identified two other purposes of §111: 4 and 5. The standards to the extent practical must force new sources to burn high-sulfur fuel thus freeing low-sulfur fuel for use in existing sourceswhere it is harder to control emissions and where lowsulfur fuel is needed for compliance. This will (1) allow old sources to operate longer and (2) expand environmentally acceptable energy supplies. Id. (quoting 44 Fed.Reg. 33,580, 33,581/3-33,582/1). These purposes are not relevant to the present rulemaking and, in any event, following the repeal in the 1990 CAAA of the percentage reduction requirements of the 1977 version of section 111, are no longer good law.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 173 of 403

state. 128 This does not mean that certain States would not retain certain inherent advantages – such as resource availability - over other States in attracting certain industries. For example, coal-fired power plants need large quantities of coal and water to operate, and States with those resources are more likely to attract that industry than States without those resources. In Congress’s view, what was important was that the section 111

standards themselves be uniform on a nationwide basis. 2. Maximum practicable emissions reductions The second and third purposes for the standards are, as quoted above, “reducing emissions as much as practicable” and “forc[ing] the installation of all the control technology that will ever be necessary at the time of construction.” These purposes apply to all pollutants that are subject to section 111, including greenhouse gases. Section 111 applies by its terms to a range of pollutants. For example, CAA §111(d)(1)(A), which applies to existing sources, references National Ambient Air Quality Standards (NAAQS) pollutants that EPA lists by rule under CAA § 108, air toxics that are listed under CAA § 112, and any other type of air pollutant. The U.S. Supreme Court has made it clear that CAA §111 applies to GHGs because (i) §111 applies to “air

128 See S. Rep. 91-1196 at 16 (1970 Senate Committee Report)),.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 174 of 403 pollutants,” CAA §§111(a)(1), 111(d)(1)(A), and in Massachusetts

v. EPA , 549 U.S. 497 (2007), the Supreme Court held that this term includes GHGs; and (ii) in American Electric Power Company

v. Connecticut , 131 S.Ct. 2527 (2011), the Supreme Court based its holding that “the Clean Air Act and the EPA actions it authorizes displace any federal common law right to seek

abatement of carbon-dioxide emissions from fossil fuel-fired power plants” on the grounds that CAA section 111 “provides a

means to seek limits on emissions of carbon dioxide from domestic power plants....” 129 The legislative history of CAA §111 and the D.C. Court have articulated these purposes of reducing emissions and forcing the up-front installation of technology so that they apply to all pollutants subject to CAA §111. The 1977 House Committee Report noted, “In the [1970] Congress [sic : Congress’s] view, it was only right that the costs of applying best practicable control technology be considered by the owner of a large new source of pollution as a normal and proper expense of doing business.” 130 Similarly, the 1970 Senate Committee Report stated: The implicit consideration of economic factors in determining whether technology is “available” should

129 American Electric Power , 131 S.Ct. at 2538. 130 1977 House Committee Report at 184.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 175 of 403

not affect the usefulness of this section. The overriding purpose of this section would be to prevent new air pollution problems, and toward that end, maximum feasible control of new sources at the time of their construction is seen by the committee as the most effective and, in the long run, the least expensive approach. 131 The D.C. Circuit, in Essex Chemical Corp. v. Ruckelshaus , 486 F.2d 427 (D.C. Cir. 1973) cited the legislative history in stating that it was necessary to “[k]eep[] in mind Congress' intent that new plants be controlled to the ‘maximum practicable degree.’” 132 Thus, a section 111 standard of performance controlling GHGs must be evaluated in light of the congressional purposes of “reducing emissions as much as practicable” and “forc[ing] the installation of all the control technology that ever will be necessary ... at the time of construction.” In fact, these purposes seem particularly important in the case of standards for coal-fired power plants because (i) these plants are the largest emitters of CO 2 and, as a result, provide the most important opportunity for controlling emissions; and (ii) new power plants have expected lifetimes of as long as 50 years and possibly longer. 3. Technology forcing

131 S. Comm. Rep. No. 91-1196 at 16. 132 Essex Chemical Corp. v. Ruckelshaus , 486 F.2d at 437 & n. 27 (citing Summary of the Provisions of Conference Agreement on the Clean Air Amendments of 1970, 116 Cong. Rec. 42384, 42385 (1970)). Comment [A64]: EPA may want to consider reiterating this point and citation (copied below) from earlier about how section 111 looks towards what may be fairly projected, which is not clear from the case law cited in this section. The Court explained that a standard of performance is “achievable” if a technology can reasonably be projected to be available to new sources at the time they are constructed that will allow them to meet the standard. Specifically, the D.C. Circuit explained:

Section 111 looks toward what may fairly be projected for the regulated future, rather than the state of the art at present, since it is addressed to standards for new plants....- It is the “achievability” of the proposed standard that is in issue.... The Senate Report made clear that it did not intend that the technology “must be in actual routine use somewhere.” The essential question was rather whether the technology would be available for installation in new plants.... The Administrator may make a projection based on existing technology, though that projection is subject to the restraints of reasonableness and cannot be based on “crystal ball” inquiry. 1***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 176 of 403 The last purpose the D.C. Circuit in Sierra Club v. Costle stated – “[t]he standards should be stringent in order to force the development of improved technology” – was based on the 1977 House Committee Report. 133 The full statement in that report provides a more robust articulation of Congress’s purposes: [T]he best technology requirement was intended to create incentives for improved technology, which could achieve greater or equivalent emission reduction at equivalent or lower cost, energy demand, and environmental impacts. This was to be accomplished by assuring any vendor who produced such an improved technological system that the standards would be revised to reflect that improvement, and a guaranteed market for the technology would thereby be created. 134 According to the House Committee Report, this statement describes the purposes of the 1970 CAAA, and it is clearly consistent with other statements in the 1970 CAAA legislative history. For example, the 1970 Senate Committee Report stated: Standards of performance should provide an incentive for industries to work toward constant improvement in techniques for preventing and controlling emissions from stationary sources, since more effective emission control will provide greater latitude in the selection of sites for new facilities. 135

133 Sierra Club v. Costle , 657 F.2d at 325 & n.83 (quoting 44 Fed.Reg. 33,580, 33,581/3-33,582/1 (EPA summary of the six purposes identified in the 1977 House Committee Report, H.R. Rep. No. 95-294, 95th Cong., 1st Sess. 184-86 (1977)) 134 1977 H. Comm. Rep. at 184-86 (GLH at 2651-53) 135 S.Rep. 91-1196 at 16 (1970). The technology-forcing nature of §111 is consistent with the technology-forcing nature of the 1970 CAAA as a whole. The principal Senate author of the 1970 CAAA, Sen. Edmund Muskie (D-ME), during the Senate floor debate, Comment [A65]: On its own, couldn’t this be read to mean that 111 incentivizes new technologies through a process where a vendor produces a new innovation and then the standard moves up to that level of performance (rewarding the vendor by then guaranteeing a market) vs. being “forcing” in the sense that it sets a forward looking standard that vendors must then meet? For this reason, it may be helpful to consider reiterating here the case law supporting a reading that 111 looks towards what may be fairly projected (see previous comment).***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 177 of 403

Similarly, the 1977 Senate Committee Report stated: In passing the Clean Air Amendments of 1970, the Congress for the first time imposed a requirement for specified levels of control technology. The section 111 Standards of Performance for New Stationary Sources required the use of the “best system of emission reduction which (taking into account the cost of achieving such reduction) the Administrator determines has been adequately demonstrated.” This requirement sought to assure the use of available technology and to stimulate the development of new technology. 136

The legislative history just quoted identifies three different ways that Congress designed section 111 to authorize standards of performance that promote technological improvement:

described the overall requirements of the 1970 and then observed: These five sets of requirements will be difficult to meet. But the committee is convinced that industry can make compliance with them possible or impossible. It is completely within their control. Industry has been presented with challenges in the past that seemed impossible to meet, but has been made possible.

. 136 S. Rep. 95-127 at 17 (1977), cited in Sierra Club v. Costle , 657 F.2d at 346 n. 174. The 1977 CAAA legislative history is replete with other references to the technology forcing nature of §111 or the CAAA as a whole. See 1977 Clean Air Act Conference Report: Statement of Intent; Clarification of Select Provisions, 123 Cong. Rec. 27071 (1977) (quoted in Sierra Club v. Costle , 657 F.2d at 346 n. 174) (one of the enumerated purposes of section 111 was to “create incentives for new technology”); __ Cong. Reg. __ (May 24, 1977) (statement of Rep. Meads) (”The main purposes of the Clean Air Act Amendments of 1977 are as follows: ... tenth, to promote the utilization of new technologies for pollution choice”).***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 178 of 403 (i) the development of technology that may be treated as the “best system of emission reduction ... adequately demonstrated;” under section 111(a)(1) 137 ; (ii) the expanded use of the best demonstrated technology; 138 and (iii) the development of emerging technology. 139

G. Chevron framework Above, we discuss how in Sierra Club v. Costle the D.C. Circuit interpreted the definition of “standard of performance” in CAA §111(a)(1), among other things, to authorize the EPA to balance economic, environmental, or energy factors through a nationwide lens, and to encompass technology forcing. The D.C. Circuit handed down this decision in 1981, and therefore it did not employ the two-step framework for statutory construction in federal rulemaking that the U.S. Supreme Court mandated in 1984,

in Chevron U.S.A. Inc. v. NRDC , 467 U.S. 837 (1984). However, the D.C. Circuit’s interpretations are fully consistent with the

137 See Portland Cement Ass’n v.Ruckelshaus, 486 F.2d 375, 391 (D.C. Cir. 1973) (the best system of emission reduction must “look[] toward what may fairly be projected for the regulated future, rather than the state of the art at present”). 138 See 1970 Senate Committee Report No. 91-1196 at 15, GLH at 415 (“The maximum use of available means of preventing and controlling air pollution is essential to the elimination of new pollution problems”). 139 See Sierra Club v. Costle , 657 F.2d at 351 (upholding a standard of performance designed to promote the use of an emerging technology).

.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 179 of 403

Chevron framework.

In Chevron , the Supreme Court held that an agency must, at Step 1, determine whether Congress’s intent as to the specific matter at issue is clear, and, if so, the agency must give effect to that intent. If congressional intent is not clear, then, at Step 2, the agency has discretion to fashion an interpretation that is a reasonable construction of the

statute. 140 As noted, under CAA section 111(a)(1), a standard of performance must be based on the “best system of emission reduction which (taking into account the cost of achieving such reduction and any nonair quality health and environmental impact and energy requirements) ... has been adequately demonstrated.” The terms “best system of emission reduction,” “cost,” and “energy requirements,” on their face, can be interpreted to apply on a regionwide or nationwide basis, and are not limited to the individual source. Thus, this interpretation is supportable under Chevron step 1, but even if not, then the EPA considers the interpretation supportable under step 2 because it is reasonable and consistent with the purposes of the CAA. Similarly, the technology-development interpretation is supportable under Chevron step 1 because encouraging the

140 Chevron U.S.A. Inc. v. NRDC , 467 U.S. 837, 842-43 (1984).***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 180 of 403utilization or development of improved technology is selfevidently a consideration in determining the “best system of emission reduction” and was clearly a focus of the legislative history 141 , but even if that interpretation is not supportable

under Chevron step 1, then the EPA considers the interpretation supportable under step 2 because it is reasonable and consistent with the purposes of the CAA. H. Agency discretion

The D.C. Circuit has made clear that the EPA has broad discretion in determining the appropriate standard of performance under the definition in CAA §111(a)(1), quoted above. Specifically, in Sierra Club v. Costle , 657 F.2d 298 (D.C. Cir. 1981), the Court explained that “section 111(a) explicitly instructs the EPA to balance multiple concerns when promulgating a NSPS,” 142 and emphasized that “[t]he text gives the EPA broad discretion to weigh different factors in setting

the standard.” 143 In Lignite Energy Council v. EPA , 198 F.3d 930 (D.C. Cir. 1999), the Court reiterated: Because section 111 does not set forth the weight that should be assigned to each of these factors, we have granted the agency a great degree of discretion in balancing them.... EPA's choice [of the ‘best system’] will be sustained unless the environmental or

141 [ D.C. Circuit Chevron step 1 case citing legislative history. ] 142 Sierra Club v. Costle , 657 F.2d at 319. 143 Sierra Club v. Costle , 657 F.2d at 321.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 181 of 403 economic costs of using the technology are exorbitant.... EPA [has] considerable discretion under section 111. 144

The important point is that Courts acknowledge that there are several factors to be considered and what is “best” depends on how much weight to give the factors. In promulgating certain standards of performance, EPA may give greater weight to particular factors than it may do so in promulgating other standards of performance. Thus, the determination of what is “best” is complex and necessarily requires an exercise of judg e ment. By analogy, the question of who is the “best” sprinter in the 100-meter dash primarily depends on only one criterion – speed – and therefore is relatively straightforward, while the question of who is the “best” baseball player depends on a more complex weighing of several criteria and therefore requires a greater exercise of judgment. I. Lack of requirement that standard be able to be met by all

sources Under CAA §111, an emissions standard may meet the requirements of a “standard of performance” even if it cannot be met by every new source in the source category that would have constructed in the absence of that standard. As discussed below,

144 Lignite Energy Council v. EPA , 198 F.3d 930, 933 (D.C. Cir. 1999) (paragraphing revised for convenience). Comment [A66]: Suggest this is not necessary.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 182 of 403 this is clear in light of (i) the legislative history of CAA §111, read in conjunction with the legislative history of the CAA as a whole; (ii) case law under analogous CAA provisions; and (iii) long-standing precedent in the EPA rulemakings under

CAA §111.1. As noted, Congress, in enacting section 111 in the 1970 CAAA, intended that the EPA promulgate uniform, nationwide controls. Congress was explicit that this meant that large industrial sources, including electric generating power plants, would be required to implement controls meeting the requirements regardless of their location. According to the 1970 Senate Committee Report: Major new facilities such as electric generating plants, kraft pulp mills, petroleum refineries, steel mills, primary smelting plants, and various other commercial and industrial operations must be controlled to the maximum practicable degree regardless of their location and industrial operations.... 145 Congress’s purposes in designing a standard that called for uniform national controls were to prevent pollution havens – caused by some states seeking competitive advantage by limiting their pollution control requirements – and to assure that areas that had good air quality would be able to maintain good air quality even after new industrial sources located there, which,

145 1970 S. Comm. Rep. at 16, GLH at 416. See 1970 Senate Debate on Conference, 91 Cong. Rec. 42,384 (Muskie)?? Comment [A67]: Note citation has question marks that need to be resolved.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 183 of 403 in turn, would allow more sources to locate there as well. 146 At the same time, Congress recognized that in light of the attainment provisions of the CAAA of 1970, sources – particularly large industrial sources, again, including electric generating plants -- may not be able to construct new facilities anywhere in the country; that is, an area with air quality at or above the NAAQS limits might not have enough room in its airshed

to accommodate these new facilities. The 1970 Senate Committee Report stated, “[l]and use policies must be developed to prevent location of facilities which are not compatible with implementation of national standards.” 147 Senator Muskie added: Land use planning and control should be used by State, local, and regional agencies as a method of minimizing air pollution. Large industries and power generating facilities should be located in places where their adverse effect on the air is minimal. There is a need for State or regional agencies to revise proposed power plant sites to assure that a number of environmental values, including air pollution, are considered. 148 The 1970 CAAA legislative history includes other statements that also recognize that under the newly required air pollution control requirements, new sources may not be able to build anywhere in the country and, in fact, some existing sources

146 See S. Comm. Rep. at 16, GLH at 416. 147 1970 Sen. Comm. Rep, 91-1196 (91 st Cong., 2d Sess) p. 2: 148 1970 Senate Debate, GLH at 37 (Sept. 21, 1970) (statement of Sen. ?? Muskie?/] maybe p. 32,917.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 184 of 403 might have to be shut down. 149 At the time, Congress expected that local air quality concerns would be the reason why some sources would not be able to locate in certain places.

Thus I Thus, i n 1970, Congress designed section 111 to require uniform national controls for large industrial facilities, while recognizing that those facilities could not necessarily construct in every place in the country. Although at the time, Congress expected that local air quality concerns would be the reason why some sources would not be able to locate in certain places, Thus, if for any reason, if the reason it

turns out that sources are not able to locate in certain places because of the air pollution control requirements, to be related

to the emission limits that the EPA promulgates under section

111 , that such action should not be viewed as inconsistent with section 111. For example, if the EPA promulgates section 111 emission limits based on a particular type of technology, and for economic or technical reasons, sources are able to utilize that technology in only certain parts of the country and not other parts, that result should not be viewed as inconsistent with congressional intent under CAA section 111. Rather, that result is consistent with Congress’s recognition that certain sources may be precluded from locating in certain areas.

149 [cites] Comment [A68]: Moved to paragraph discussing legislative history.

Comment [A69]: Suggested edits for consideration.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 185 of 403 2. Case law under analogous CAA provisions Under analogous CAA provisions, the D.C. Circuit has recognized that the EPA may promulgate uniform standards that apply to new sources in a group or category of sources, even though some types of those new sources that would otherwise construct would no longer be able to construct because they

could not meet the standard. One of these cases was

International Harvester Co. v. EPA , 478 F.2d 615 (D.C. Cir. 1973). There, the EPA declined to exercise its discretion under the CAA mobile source provisions, as they read at that time (42USC 1857f-1(b)(5)(D) (1970 CAAA)), to grant automakers a oneyear extension to comply with exhaust standards. The EPA stated

that the automakers had failed to meet their burden of establishing that controls were not available. The EPA based its decision on grounds that certain technology was available for the motor vehicles in question. The EPA dismissed the automakers’ objections that this technology could not feasibly be installed in all models or engine types, and the EPA explained that the public’s “basic demand” for automobiles could be met by the models and engine types that could feasibly install that technology. 478 F.2d at 626. Although the Court remanded the EPA’s decision not to grant the one-year extension, it agreed with the EPA on this point,***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 186 of 403 stating: We are inclined to agree with the Administrator that as long as feasible technology permits the demand for new passenger automobiles to be generally met, the basic requirements of the Act would be satisfied, even though this might occasion fewer models and a more limited choice of engine types. The driving preferences of hot rodders are not to outweigh the goal of a clean environment. 150

Similarly, in a 2007 decision under CAA §112, NRDC v. EPA , 489 F.3d 1364, 1376 (D.C. Cir. 2007) the D.C. Circuit upheld the EPA’s decision to apply the same hazardous air pollutant requirements to different types of plywood and composite wood products facilities – even though one of those types of facilities faced greater difficulties meeting the requirements than the other types of facilities – in part on the grounds that the facilities “compet[ed] in the same markets.” 151 3. Section 111 rulemaking precedent Through long-standing rulemaking precedent, the EPA has taken the position that section 111 authorizes a standard of performance for a source category that may not be feasible for all types of new sources in the category, as long as there are other types of sources in the category that can serve the same function and meet the standard. Specifically, in a 1976

150 International Harvester Co. v. EPA , 478 F.2d at 640. 151 NRDC v. EPA, 489 F.3d at 1376

. Comment [A70]: This is helpful – is there any further elaboration that could be made on this point, particularly to connect this with the electricity market?

Comment [A71]: Added for clarification***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 187 of 403 rulemaking under section 111 covering primary copper, zinc, and lead smelters, the EPA established, as the standard of performance, a single standard for SO 2 emissions for new construction or modifications of reverberatory, flash, and electric smelting furnaces in primary copper smelters that process materials with low levels of volatile impurities. The EPA acknowledged that although for flash and electric smelting furnaces, the cost of the controls was “reasonable,” for reverberatory smelting furnaces, the cost of the standard was “unreasonable in most cases.” Even so, the EPA determined that this standard would not adversely affect new construction or modification of primary copper smelters processing materials containing low levels of volatile impurities because new construction could use flash and electric smelting furnaces, and existing sources could expand without increasing emissions. 152 The EPA explained: [T]he Agency believes that section 111 authorizes the promulgation of one standard applicable to all processes used by a class of sources, in order that the standard may reflect the maximum feasible control for that class. When the application of a standard to a given process would effectively ban the process, however, a separate standard must be prescribed for it unless some other process(es) is available to perform the function at reasonable cost

....

152 Standards of Performance for New Stationary Sources, Primary Copper, Zinc, and Lead Smelters, 41 FR ____, 2333 (Jan. 15, 1976).***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 188 of 403

The Administrator has determined that the flash copper smelting process is available and will perform the function of the reverberatory copper smelting process at reasonable cost.... 153

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

**Boilers and IGCCs**

A. Overview In this section we explain our rationale for concluding that partial implementation of CCS is the best system of emission reduction adequately demonstrated (BSER) for new fossil

fuel-fired boiler and IGCC EGUs. As noted, CAA §111 and subsequent court decisions establish

a set of factors for the EPA to consider in a BSER determination, including criteria listed in CAA §111 or identified in the court decisions and the underlying purposes of §111. Key factors include: emission reductions, technical feasibility, costs, and encouragement of technology. Other factors, such as energy impacts, may also be important. As also noted, the EPA has discretion in balancing those factors, and may balance them differently in promulgating standards for different source categories. The EPA considered three different control technology

153 41 FR at 2333 (emphasis added). Comment [A72]: Should this reference standards of performance instead of BSER? Or, both?***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 189 of 403 configurations as potentially representing the BSER for new fossil fuel-fired boilers and IGCC units. Power company announcements indicate that the few new coal-fired projects that may occur will likely consider one or more of these three configurations. The three alternatives the EPA considered in the BSER analysis are: (1) highly efficient new generation technology that does not include any level of CCS, (2) new generation technology with “full capture” CCS (that is, CCS capture of at least 90 percent CO 2 emissions) and (3) new generation technology with “partial capture” CCS (that is, CCS capture of a lower level of CO 2 emissions). We discuss each of these alternatives below, and explain why we propose that partial capture CCS qualifies as the BSER. We first discuss the technical systems that we considered for the BSER, our evaluations of them, and our reasons for determining that only partial CCS meets the criteria to qualify

as the BSER. We include in this discussion our rationale for selecting 1,100 lb CO 2 /MWh as the emission limitation for these sources and why we seek comment on a range from 1,000 to 1,200

lb CO 2 /MWh. We next discuss our rationale for allowing a 60- operating-month averaging period as an alternative compliance method, with the requirement that sources choosing that method Comment [A73]: Is it “few” or “none”. Suggest adding a sentence before power company sentence stating that EIA projects none,.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 190 of 403 meet a limit of between 1,000 lb CO 2 /MWh and 1,050 lb CO 2 /MWh. 154 We then explain our rationale for the requirements for geologic sequestration. B. Identification of the best system of emission reduction

1. Highly efficient new generation without CCS technology Some commenters on the April 2012 proposal suggested that

the emission limitation for new coal-fired EGUs should be based on the performance of highly efficient generation technology that does not include CCS, such as (i) a supercritical 155 pulverized coal (SCPC) or circulating fluidized bed (CFB) boiler, or (ii) a modern, well-performing IGCC unit. These options are clearly technically feasible. However, we do not consider them to qualify as the BSER for the following

reasons:

a. Lack of significant CO 2 reductions Because of the large amount of CO 2 emissions from solid-fuel fired power plants, it is important, in promulgating a standard

154 This is on a gross output basis. All other emissions in this section are listed as gross output unless specifically noted otherwise. 155 Subcritical coal-fired boilers are designed and operated with a steam cycle below the critical point of water. Supercritical coal-fired boilers are designed and operated with a steam cycle above the critical point of water. Increasing the steam pressure and temperature increases the amount of energy within the steam, so that more energy can be extracted by the steam turbine, which in turn leads to increased efficiency and lower emissions. Comment [A74]: The NOPR uses “clearly” a fair amount, and the use does not add persuasiveness. Consider omitting.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 191 of 403 of performance for these sources, to give effect to the purpose of CAA §111 of providing “as much [emission reduction] as practicable.” 156 Accordingly, we reviewed the emission rates of efficient PC and CFB units. According to the DOE/NETL estimates, a new subcritical pulverized coal (PC) unit firing bituminous coal would emit 1,783 lb CO 2 /MWh, 157 a new SCPC unit using bituminous coal would emit 1,675 lb CO 2 /MWh, and a new IGCC

unit 158 would emit 1,434 lb CO 2 /MWh. 159 New power sector projects using coal as a primary fuel that have been proposed or are currently under construction are generally SCPC or IGCC projects. For example, since 2007, almost all coal-fueled EGUs that have broken ground have been high performing versions of SCPC or IGCC projects. 160 Among those plants are: (1) AEP’s John W. Turk, Jr. Power Plant, a 600 MW

156 Sierra Club, F.2d at 327 & n. 83 (quoting 44 FR at 33,581/3 – 33,582/1). 157 Exhibit ES-2 from “Cost and Performance Baseline for Fossil Energy Plants Volume 1: Bituminous Coal and Natural Gas to Electricity”, Revision 2, Report DOE/NETL-2010/1397 (November 2010). 158 “Case 1” from Exhibit ES-2 from “Cost and Performance Baseline for Fossil Energy Plants Volume 1: Bituminous Coal andNatural Gas to Electricity”, Revision 2, Report DOE/NETL2010/1397 (November 2010). 159 The comparable emissions on a net basis are: subcritical PC – 1,888 lb CO 2 /MWh; supercritical PC – 1,768 lb CO 2 /MWh; and IGCC – 1,723 lb CO 2 /MWh. 160 The only exception that we are aware of is the Virginia City subcritical CFB unit Comment [A75]: What are the CO2 emissions of the subcritical CFB? The FN contains only minimal discussion; should elaborate.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 192 of 403 ultra-supercritical 161 PC (USCPC) facility located in the southwest corner of Arkansas; (2) Duke Power’s Edwardsport plant, a 618 MW coal IGCC unit located in Knox County, Indiana; and (3) Southern Company’s Kemper County Energy Facility, a 582 MW lignite IGCC unit located in Kemper County, Mississippi. These facilities all use advanced generation technology: Turk, as noted, is an ultra-supercritical boiler; Edwardsport is an IGCC unit that is “CCS ready;” and Kemper is an IGCC unit that will implement partial CCS. Under these circumstances, in this rule, identifying a new supercritical unit as the BSER and requiring the associated emission limitation of approximately 1,675 lb CO 2 /MWh, would provide little meaningful CO 2 emission reductions for this source category. As noted, for the most part, new sources are already designed to achieve at least that emission limitation. Identifying IGCC as the BSER and requiring the associated emission limitation of approximately 1,434 lb CO 2 /MWh, would provide some CO 2 emission reductions from the segment of the industry that would otherwise construct new PC units, but not from the segment of the industry that would already construct

161 Ultra-supercritical (USC) and advanced ultra-supercritical (A-USC) are terms often used to designate a coal-fired power plant design with steam conditions well above the critical point.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 193 of 403

new IGCC units. As a result, emission reductions in the amount that would result from an emission standard based on SCPC/USCPC or even IGCC as the BSER would not be consistent with the purpose of CAA §111 to achieve “as much [emission reduction] as practicable.” 162 As we discuss below, identifying CCS-partial capture as the BSER would provide for significantly greater emissions reductions.

b. Lack of incentive for technological innovation Identifying highly efficient generation technology as the BSER would not achieve another purpose of CAA §111, to encourage the development and implementation of control technology. At present, CCS technologies are the most promising options to achieve significant reductions in CO 2 emissions from solid fossil-fuel fired EGUs. A standard based on the performance of highly efficient coal-fired generation does not advance the development and implementation of control technologies that

reduce CO 2 emissions. On the contrary, such a standard could impede the advancement of CCS technology by creating regulatory disincentives for such technology. In 2011, American Electric Power (AEP) deferred construction of a large-scale CCS retrofit

162 Sierra Club , F.2d at 327 & n. 83 (quoting 44 FR at 33,581/3 – 33,582/1). Comment [A76]: Promising or effective?***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 194 of 403 demonstration project on one of their coal-fired power plants because the state’s utility regulators would not approve cost recovery for CCS investments without a regulatory requirement to

reduce CO 2 emissions. AEP’s chairman was explicit on this point, stating in a July 17, 2011 press release announcing the

deferral: We are placing the project on hold until economic and policy conditions create a viable path forward ... We are clearly in a classic ‘which comes first?’ situation. The commercialization of this technology is vital if owners of coal-fueled generation are to comply with potential future climate regulations without prematurely retiring efficient, cost-effective generating capacity. But as a regulated utility, it is impossible to gain regulatory approval to recover our share of the costs for validating and deploying the technology without federal requirements to reduce greenhouse gas emissions already in place. The uncertainty also makes it difficult to attract partners to help fund the industry’s share. 163

As we discuss below, regulatory requirements for CO 2 reductions with some level of CCS as the BSER will promote further development of the technology.

2. Carbon capture and storage

We have also considered whether the emission limitation for new coal-fired EGUs should be based on the performance of CCS, including either “full capture” CCS that treats the entire flue gas or syngas stream to achieve on the order of 90 percent

163 http://www.aep.com/newsroom/newsreleases/?id=1704***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 195 of 403

reduction in CO 2 emissions, or “partial capture” CCS that achieves some level less than 90 percent of capture. We propose that implementation of partial capture CCS technology is the BSER for new fossil fuel-fired boilers and

IGCC units because it fulfills the criteria established under CAA §111. In the sections that follow, we explain the technical configurations that facilitate full and partial capture, describe the operational flexibilities that partial capture offers, and then identify and justify the emission rate that we propose based on partial capture. After that, we discuss the criteria for BSER, and describe why partial capture meets those criteria and why full capture does not. Among other things, partial capture provides meaningful emission reductions, it has been adequately demonstrated to be technically feasible, it can be implemented at a not unreasonable cost, and it promotes deployment and further development of the technology.

3. Technical configurations for CCS The DOE’s National Energy Technology Laboratory (NETL) performed a study to establish the cost and performance for a range of CO 2 capture levels for new SCPC and IGCC power plants. 164

164 “Cost and Performance of PC and IGCC Plants for a Range of Carbon Dioxide Capture”, DOE/NETL-2011/1498, May 27, 2011.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 196 of 403 The study identified technical configurations that were tailored to achieve a specific level of carbon capture.

a. SCPC For the new SCPC case, the study assumed a new SCPC boiler with a combination of low-NOx burners (LNB) with overfire air (OFA) and a selective catalytic reduction (SCR) system for NOx control. The plant was assumed to have a fabric filter and a wet limestone flue gas desulfurization (FGD) scrubber for particulate matter and sulfur dioxide (SO 2 ) control, respectively. The plant was also assumed to have a sodium hydroxide (NaOH) polishing scrubber to ensure that the flue gas entering the CO 2 capture system has a SO 2 concentration of 10 ppmv or less. The SCPC plant was equipped with Fluor’s Econamine

FG Plus SM process for post-combustion CO 2 capture via temperature swing absorption with a monoethanolamine (MEA) solution as the

chemical solvent. The study’s authors identified two options for achieving partial capture (i.e., less than 90 percent CO 2 capture) in the SCPC unit. The first option was to process the entire flue gas stream through the MEA capture system at reduced solvent circulation rates. The second option was to maintain the same high solvent circulation rate and steam stripping requirement as would be used for full capture but only treat a portion of the***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 197 of 403 total flue gas stream. The authors determined that the second approach – the “slip stream” approach - was the most economical.

The authors further noted that the cost of CO 2 capture with an amine scrubbing process is dependent on the volume of gas being treated, and a reduction in flue gas flow rate will: (1) decrease the quantity of energy consumed by flue gas blowers, (2) reduce the size of the CO 2 absorption columns, and (3) trim the cooling water requirement of the direct contact cooling system. The slip stream approach leads to lower capital and operating costs. All of the partial capture cases in the NETL study assumed this approach.

a. IGCC For a new IGCC unit, the product syngas would contain primarily hydrogen (H 2 ), carbon monoxide (CO) and some lesser

amount of CO 2 . 165 The amount of CO 2 can be increased by “shifting” the composition via the catalytic water-gas shift (WGS) reaction. This process involves the catalytic reaction of steam (“water”) with CO (“gas”) to form H 2 and CO 2 . An emission standard that requires partial capture of CO 2 from the syngas could be met by adjusting the level of CO 2 in the syngas stream

165 The amount of CO 2 in un-shifted syngas depends upon the specific gasifier technology used, the operating conditions, and the fuel used; but is typically less than 20 volume percent (http://www.netl.doe.gov/technologies/coalpower/gasification/gas ifipedia/4-gasifiers/4-3_syngas-table2.html).***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 198 of 403 by controlling the level of syngas “shift” prior to treatment in the pre-combustion acid gas treatment system. For a new IGCC EGU, the study’s authors assumed the use of the GE gasifier coupled with a variety of potentialconfigurations (i.e., no WGS reactor, single-stage WGS, twostage WGS, varying WGS bypass ratios, and CO 2 scrubber removal efficiency). The study evaluated a number of IGCC plant configurations. The first was an IGCC that used the SelexolTM process for acid gas control (i.e., hydrogen sulfide (H 2 S) and

CO 2 ) but no WGS reactor. This unit was capable of CO 2 capture ranging from zero up to 25 percent. The no-CO 2 capture case employed a one-stage SelexolTM unit for H 2 S control and the 25 percent CO 2 capture case utilized a two-stage SelexolTM unit to

maximize CO 2 capture from the unshifted syngas (i.e., >90 percent

of the CO 2 from the unshifted syngas was captured in the second stage SelexolTM scrubber). To achieve moderate levels of partial CO 2 capture – approximately 25 to 75 percent - the IGCC was configured with a single-stage WGS reactor with bypass and a two-stage SelexolTM unit. Varying the extent of the WGS reaction by controlling the amount of syngas that was processed through the WGS reactor (by controlling the amount that bypassed the WGS reactor) manipulated the level of CO 2 capture. As more syngas is processed***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 199 of 403 through the WGS reactor, the steam demand increases. The SelexolTM removal efficiency was manipulated by varying the solvent circulation rate. Thus, a facility using this configuration could select or “dial in” a level of control of between 25 – 75 percent. To achieve higher CO 2 capture levels – levels greater than 75 percent - the IGCC was configured with a two-stage WGS with bypass and the two-stage acid gas (SelexolTM) scrubbing system. The facility could “dial in” a level of control of between 25 to greater than 90 percent by controlling the WGS bypass and the

SelexolTM scrubber recirculation rates. The water-gas shift involves the following catalytic reaction of syngas carbon monoxide and steam:

CO + H 2 O ∆ ՜ CO 2 + H 2 Since the syngas initially contains primarily CO and H 2 , this shift reaction diminishes the concentration of CO and

enriches the concentration of H 2 in the pre-combustion syngas stream. An unshifted or partially shifted syngas can be combusted using a typical combustion turbine. However, as the

level of H 2 in the syngas increases, the more the syngas must be

diluted with N 2 or air. Very high levels of H 2 in the syngas stream require use of a specialty hydrogen turbine.

4. Operational and design flexibility***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 200 of 403 To this point, most of the studies involving research, development and demonstration of carbon capture technology, along with most of the studies that have modeled the costs and implementation of such technology have assumed capture requirements of 90 percent for fossil fuel-fired power plants (“full capture”). However, the EPA believes that partial capture provides significant benefits because an emission limit based on partial capture offers operators considerable operational flexibility. With such emission limits, project developers would have the option of designing and installing CO 2 capture technology at a size sufficient to treat the entire flue gas stream, with the capability to meet CO 2 emission limits that are much lower than required. The operator of the plant could then choose to achieve those deeper capture rates during non-peak electricity demand periods and to achieve lesser capture rates (and thus generate more electricity) during peak electricity demand periods. This type of operational flexibility provides owners and operators the opportunity to optimize the operation and minimize the cost of CCS in new fossil fuel-fired projects. In addition, an emission standard that can be met with partial capture offers the opportunity for design flexibility. A project developer of a new conventional coal-fired plant (i.e., a new supercritical PC or CFB) could install post-combustion CO 2***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 201 of 403 scrubbers that have been designed and sized to treat only a portion of the flue gas stream. For a new IGCC unit, as noted, an emission standard that requires partial capture of CO 2 offers operational flexibility because the standard could be met by adjusting the level of CO 2 in the syngas stream by controlling the level of syngas “shift” prior to treatment in the pre-combustion acid gas treatment

system.

C. Determination of the level of the standard Once the EPA has determined that a technology has been adequately demonstrated based on cost and other factors, including the impact a standard will have on further technology development and therefore represents BSER, the EPA must establish an emission standard. In this case, for new fossil fuel-fired boiler and IGCC EGUs, the EPA is finding that the level of partial capture of CO 2 that qualifies as the BSER supports a standard of 1,100 lb CO 2 /MWh on a gross basis. The

level of the standard is based on the emission reductions that can be achieved by an IGCC with a single-stage WGS reactor and a two-stage acid gas removal system. According to the DOE/NETL partial capture study, an IGCC with this configuration would be expected to achieve a CO 2 emission reduction of 25 to 75 percent, which corresponds to emissions of approximately 1,060 and 380 lb***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 202 of 403

CO 2 /MWh-gross, respectively. The EPA is proposing a standard of performance of 1,100 lb CO 2 /MWh-gross, which is the high end of this range, for several reasons. First, both a new IGCC and a conventional coal-fired boiler (PC or CFB), can achieve this emission standard at a reasonable cost and the standard is based on technology that has been adequately demonstrated. The partial capture requirement and standard of performance will allow new IGCC project developers to minimize the need for multi-stage water-gas shift reactors (and the associated steam requirement) and will allow for the continued use of conventional syngas combustion turbines (rather than requiring the use of advanced hydrogen turbines). Second, this partial capture configuration will provide operators with operational flexibility. Third, this level of the standard best promotes further enhancement of the performance of existing technology and promotes continued development of new, better performing technology. It will provide developers with the opportunity to investigate new emerging and potentially lower-cost technologies. For instance, developers could build plants with the capacity to achieve deeper CO 2 reductions and choose to employ those greater capture rates during non-peak periods, and Comment [A77]: Could EPA further explain why it believes the level of standard that can be met by existing technologies would spur development of new, better performing technology?***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 203 of 403 then employ lower capture rates (and thus generate more electricity) during peak periods. While the EPA is proposing an emission rate of 1,100 lb

CO 2 /MWh, we are also soliciting comment on whether the emission limit may be more appropriately set at a different level within the range of 1,000 to 1,200 lb CO 2 /MWh. An emission rate of 1,200

lb CO 2 /MWh could potentially be met by an IGCC unit that does not include a WGS reactor – thus further reducing the capital and operating costs. An emission limit of 1,000 lb CO 2 /MWh would provide greater emission reductions and would also advance CCS technology but would offer less operational flexibility.

The next several sections review the factors for determining BSER and explain why partial capture at the level we are proposing meets those requirements, as well as why full capture does not meet some of them.

D. Extent of reductions in CO 2 emissions The proposed standard of 1,100 lb CO 2 /MWh will provide meaningful reductions in emissions. As mentioned earlier, the DOE/NETL has estimated that a new supercritical PC using bituminous coal would emit 1,675 lb CO 2 /MWh. The DOE/NETL has also estimated that a new IGCC unit would emit 1,434 lb CO 2 /MWh. The emissions would be higher for units utilizing subbituminous coal or lignite and will vary when utilizing other fossil fuels***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 204 of 403 such as petroleum coke or mixtures of fuels. We estimate that

this standard will result in reduction in emissions of at least 40 percent when compared to the expected emissions of a new supercritical PC boiler. E. Technical feasibility The EPA proposes to find that partial CCS is feasible because each step in the process has been demonstrated to befeasible through an extensive literature record, fossil fuelfired industrial plants currently in commercial operation and pilot-scale fossil fuel-fired EGUs currently in operation, andthe progress towards completion of construction of fossil fuelfired EGUs implementing CCS at commercial scale. This literature record and experience demonstrate that partial CCS is achievable for all types of new boiler and IGCC configurations. Although

much of this information also serves to demonstrate the technical feasibility of full capture, we note that the several of the CCS projects that are the furthest along are partial capture projects, which further supports our view that partial capture is BSER.

1. Literature The current status of CCS technology was described and analyzed by the 2010 Interagency Task Force on CCS, established by President Obama on February 3, 2010, co-chaired by the DOE***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 205 of 403 and the EPA, and composed of 14 executive departments and federal agencies. The Task Force was charged with proposing a plan to overcome the barriers to the widespread, cost-effective deployment of CCS within 10 years, with a goal of bringing five to ten commercial demonstration projects online by 2016. The Task Force found that, although early CCS projects face economicchallenges related to climate policy uncertainty, first-of-akind technology risks, and the current cost of CCS relative to other technologies, there are no insurmountable technological, legal, institutional, regulatory or other barriers that prevent CCS from playing a role in reducing GHG emissions. 166 The Pacific Northwest National Laboratory (PNNL) recently prepared a study that evaluated the development status of various CCS technologies for the DOE. 167 The study addressed the availability of capture processes, transportation options (CO 2 pipelines), injection technologies, and measurement, verification and monitoring technologies. The study concluded that, in general, CCS is technically viable today and that key component technologies of complete CCS systems have been deployed at scales large enough to meaningfully inform discussions about CCS deployment on large commercial fossil-

166 Report of the Interagency Task Force on Carbon Capture and Storage (August 2010), page 7. Comment [A78]: Does the task force findings say anything about leakage from geological storage and ways to manage for leakage? Suggest that this information could be cited somewhere in the rulemaking, if it exisits.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 206 of 403 fired power plants. In addition, DOE/NETL has prepared additional reports – in particular their “Cost and Performance Baseline” reports 168 including one on partial capture 169 -- that further support the technical feasibility of partial capture. 2. Capture, transportation and storage technologies Each of the core components of CCS -- CO 2 capture, compression, transportation and storage have already been implemented on a commercial scale.

a. CO 2 capture technology Capture of CO 2 from industrial gas streams has occurred since the 1930s using a variety of approaches to separate CO 2 from other gases. These processes have been used in the natural gas industry and to produce food and chemical-grade CO 2 . Although current capture technologies are feasible, the costs of CO 2 capture and compression represent the largest barriers to widespread commercialization of CCS. Currently available CO 2 capture and compression processes are estimated to represent 70

168 The “Cost and Performance Baseline” reports are a series of reports by DOE/NETL that establish estimates for the cost and performance of combustion- and gasification-based power plants - all with and without CO 2 capture and storage. Available at www.netl.doe.gov/energy-analyses/baseline_studies.html 169 “Cost and Performance of PC and IGCC Plants for a Range of Carbon Dioxide Capture”, DOE/NETL-2011/1498, May 27, 2011. Comment [A79]: It would be helpful to summarize the reports to substantiate the statement that these reports support the technical feasibility determination by EPA.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 207 of 403 to 90 percent of the overall CCS costs. 170 In general, CO 2 capture technologies applicable to coalfired power generation can be categorized into three approaches: 171

 Pre-combustion systems that are designed to separate CO 2 and

H 2 in the high-pressure syngas produced at IGCC power plants.

 Post-combustion systems that are designed to separate CO 2 from the flue gas produced by fossil-fuel combustion in

air.

 Oxy-combustion that uses high-purity O 2 , rather than air, to combust coal and thereby produce a highly concentrated CO 2

stream.Each of these three carbon capture approaches (precombustion, post-combustion, and oxy-combustion) is technologically feasible. However, each results in increased capital and operating costs and decreased electricity output (that is, an energy penalty), with a resulting increase in the cost of electricity. The energy penalty occurs because the CO 2 capture process uses some of the energy (e.g., electricity,

170 Report of the Interagency Task Force on Carbon Capture and Storage (August 2010). 171 IPCC, 2005; DOE, 2007.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 208 of 403 steam, heat) produced from the plant.

b. CO 2 transportation Carbon dioxide has been transported via pipelines in the U.S. for nearly 40 years. Approximately 50 million metric tons

of CO 2 are transported each year through 3,600 miles of pipelines. Moreover, a review of the 500 largest CO 2 point sources in the U.S. shows that 95 percent are within 50 miles of a possible geologic sequestration site, 172 which would lower transportation costs. For these reasons, the transportation component of CCS is not expected to be a significant impediment to the commercial availability of CCS in the future.

c. CO 2 storage (i) Current availability of geologic sequestration Geologic storage potential for CO 2 is widespread and available throughout the U.S. and Canada. Estimates based on DOE studies indicate that areas of the U.S. with appropriate geology have a storage potential of 2,300 billion to more than 20,000

billion metric tons of CO 2 in deep saline formations, oil and gas

172 JJ Dooley, CL Davidson, RT Dahowski, MA Wise, N Gupta, SH Kim, EL Malone (2006), Carbon Dioxide Capture and Geologic Storage: A Key Component of a Global Energy Technology Strategy to Address Climate Change. Joint Global Change Research Institute, Battelle Pacific Northwest Division. PNWD-3602. College Park, MD. Comment [A80]: Can EPA address the costs associated with any new pipelines that could be used for transportation? Or the costs to get from a facility to a GS site?

Comment [A81]: Can EPA provide a more direct explanation of how the permanence of storage has been demonstrated? The explanation that follows talks about how storage locations and opportunities are available for geologic sequestration and EOR, but does not discuss evidence that CO2 can actually be technically stored for long periods of time. I believe that evidence exists, but would be good to explain directly.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 209 of 403

reservoirs and un-mineable coal seams. 173 Other types of geologic formations such as organic rich shale and basalt may also have the ability to store CO 2 ; and the DOE is currently evaluating their potential storage capacity. Potential geologic sequestration sites must undergo appropriate site characterization to ensure that the site can safely and securely store CO 2 . Estimates of CO 2 storage resources by state/province are compiled by the DOE’s National Carbon Sequestration Database and Geographic Information System (NATCARB). Further evidence of the widespread availability CO 2 storage reserves in the U.S. comes from the Department of Interior’s U.S. Geological Survey (USGS) which has recently completed a comprehensive evaluation of the technically accessible storage resource for carbon storage for 36 sedimentary basins in the

onshore areas and State waters of the United States. 174 The USGS assessment estimates a mean of 3,000 billion metric tons of

subsurface CO 2 storage potential across the United States. For comparison, this amount is 500 times the 2011 annual U.S.

173 The United States 2012 Carbon Utilization and Storage Atlas, Fourth Edition, U.S Department of Energy, Office of Fossil Energy, National Energy Technology Laboratory (NETL). 174 U.S. Geological Survey Geologic Carbon Dioxide Storage Resources Assessment Team, 2013, National assessment of geologic carbon dioxide storage resources – Results: U.S. Geological Survey Circular 1386, 41 p., http://pubs.usgs.gov/fs/2013/1386/.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 210 of 403 energy-related CO 2 emissions of 5.5 Gigatons (Gt). 175 Nearly every state in the U.S. has or is in close proximity to formations with carbon storage potential including vast areas offshore. At the end of 2012 three large-scale geologic sequestration projects were underway in the U.S., with a goal of injecting more than 1 million tonnes of CO 2 . The U.S. experience with large-scale CO 2 injection, such as at enhanced oil and gas recovery projects, combined with ongoing research, development, and demonstration programs in the U.S. and throughout the world, provide confidence that the storage - along with capture, compression and transport - of large amounts of CO 2 can be

achieved. (ii) Current availability of enhanced oil and gas recovery Geologic storage options also include use of CO 2 in enhanced oil recovery. Enhanced recovery (ER), which includes both enhanced oil and gas recovery (EOR and EGR), refers to the injection of fluids into a reservoir to increase oil and/or gas production efficiency. ER is typically conducted at a reservoir after production yields have decreased from primary production. Fluids commonly used for ER include brine, fresh water, steam,

175 U.S. Geological Survey Geologic Carbon Dioxide Storage Resources Assessment Team, 2013, National assessment of geologic carbon dioxide storage resources – Summary: U.S. Geological Survey Factsheet 2013-3020, 6p.http://pubs.usgs.gov/fs/2013/3020/. Comment [A82]: And to put this in context, consider adding a clause at the end that notes what percent 1 million tonnes of CO2 is out of total availability estimates in the US

Comment [A83]: This seems less focused on availability of CO2 storage. Consider omitting.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 211 of 403 nitrogen, alkali solutions, surfactant solutions, polymer solutions, and carbon dioxide. EOR using carbon dioxide,

sometimes referred to as ’CO 2 flooding’ or CO 2 -EOR, involves injecting carbon dioxide into an oil reservoir to help mobilize the remaining oil and make it available for recovery. The crude

oil and CO 2 mixture is produced, and sent to a separator where the crude oil is separated from the gaseous hydrocarbons and CO 2 . The gaseous CO 2 -rich stream then is typically dehydrated, purified to remove hydrocarbons, recompressed, and re-injected into the oil or natural gas reservoir to further enhance

recovery.

CO 2 -EOR has been successfully used at many production fields throughout the U.S. to increase oil recovery. The oil and natural gas industry in the United States has over 40 years of experience of injection and monitoring of CO 2 in the deep subsurface for the purposes of enhancing oil and natural gas production. This experience provides a strong foundation for the injection and monitoring technologies that will be needed for successful deployment of CCS. Although deep saline formations provide the most CO 2 storage opportunity (2,102 to 20,043 billion metric tons), oil and gas reservoirs are currently estimated to Comment [A84]: Does the monitoring ensure that CO2 is stored long-term, and therefore “successful”. Are there references that could be added here that provide background on the monitoring of CO2-EOR?***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 212 of 403

have 226 billion metric tons of CO 2 storage resource. 176 The EPA anticipates that many early geologic sequestration projects may be sited in active or depleted oil and gas reservoirs because these formations have been previously well characterized for hydrocarbon recovery, likely already have suitable infrastructure (e.g., wells, pipelines, etc.), have an associated economic benefit of oil production, and may be suitable for long term containment of CO 2 . CO 2 -EOR is the fastest-growing EOR technique in the U.S., providing approximately 281,000 barrels of oil per day in the U.S. which equals about 6 percent of U.S. crude oil production. The vast majority of CO 2 -EOR is conducted in oil reservoirs in the U.S. Permian Basin, which extends through southwest Texas

and southeast New Mexico. Other U.S. states where CO 2 -EOR is utilized are Alabama, Colorado, Illinois, Kansas, Louisiana, Michigan, Mississippi, New Mexico, Oklahoma, Utah, and Wyoming. A well-established and expanding network of pipeline infrastructure supports CO 2 -EOR in these areas. The CO 2 supply for EOR operations currently is largely obtained from natural underground formations or domes that contain CO 2 . While natural

176 U.S. Department of Energy National Energy Technology Laboratory (2012). United States Carbon Utilization and Storage Atlas, Fourth Edition. Comment [A85]: Why is this statement qualified (“may be”)?***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 213 of 403

sources of CO 2 comprise the majority of CO 2 supplied for EOR operations, recent developments targeting anthropogenic sources

of CO 2 (e.g., ethanol plants, gas processing, refineries, power plants) have expanded or led to planned expansions in existing

infrastructure related to CO 2 -EOR. Several hundred miles of

dedicated CO 2 pipeline is under construction, planned, or proposed that would allow continued growth in CO 2 supply for EOR.

Potential sources of CO 2 for EOR continue to increase as new projects are being planned or implemented. Based on an evaluation of publicly available sources, the EPA notes there are currently twenty-two industrial source CCS projects in twelve states that are either operational, under-construction, or actively being pursued which are or will supply captured CO 2 for the purposes of EOR. This further demonstrates that CCS projects associated with large point sources are occurring due

to a demand for CO 2 by EOR operations. Nationally, according to the EPA’s Greenhouse Gas Reporting Program, over 64 million

metric tons of CO 2 were received for injection to enhanced oil recovery operations in 2011. A recent study by DOE found that the market for captured CO 2 emissions from power plants created by economically feasible CO 2 -EOR projects would be sufficient to permanently store the CO 2 emissions from 93 large (1,000 MW) Comment [A86]: Is there a reference that can be added that summarizes these projects?***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 214 of 403 coal-fired power plants operated for 30 years. 177 Based on all of these factors, the EPA anticipates opportunities to utilize CO 2 - EOR operations for geologic storage will continue to increase. Based on a recent resource assessment by the DOE, the application of next generation CO 2 -EOR technologies would significantly increase oil production areas, further expanding the geographic extent and accessibility of CO 2 -EOR operations in

the U.S. 178 Additionally, oil and gas fields now considered to be ‘depleted’ may resume operation because of increased availability and decreased cost of anthropogenic CO 2 , and developments in EOR technology, thereby increasing the demand for and accessibility of CO 2 utilization for EOR.

The use of CO 2 for EOR can significantly lower the net cost of implementing CCS. The opportunity to sell the captured CO 2 for EOR, rather than paying directly for its long-term storage, improves the overall economics of the new generating unit. According to the International Energy Agency (IEA), of the CCS projects under construction or at an advanced stage of planning, 70 percent intend to use captured CO 2 to improve recovery of oil

in mature fields.

177 “Improving Domestic Energy Security and Lowering CO 2 Emissions with “Next Generation” CO 2 -Enhanced Oil Recovery (CO 2 - EOR)”, DOE/NETL-2011/1504 (June 20, 2011). 178 Ibid.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 215 of 403 (iii) Alternatives to geologic sequestration In the development of this proposal, the EPA has identified some potential alternatives to geologic sequestration, including

but not limited to CO 2 stored in precipitated calcium carbonate and certain types of cement. The EPA solicits comment on whether these and other alternatives to geologic sequestration , permanently store CO 2 and if they are technically available for EGUs to meet the performance standard. Consideration of how these alternatives could meet the performance standard involves understanding the ultimate fate of the captured CO 2 and the degree to which the method permanently isolates the CO 2 from the atmosphere, as well as existing methodologies to verify this permanent storage. The EPA proposes that alternatives to geologic sequestration could not be used until the EPA finalizes a mechanism for that alternative to demonstrate permanent storage of CO 2 . The EPA believes that the number of cases where an EGU would seek to comply with the rule through an alternative will be very small. However the EPA wishes to encourage development of alternatives to geologic sequestration that could help offset the cost of CO 2 capture.

3. Examples of CCS demonstration projects The following is a brief summary of some examples of currently operating or planned CO 2 capture or storage systems, Comment [A87]: Considering that this standard is set forth for other alternatives, EPA should address how EPA’s proposal meets this test.

Comment [A88]: Need to clarify that this is not a complete list (or is it?).***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 216 of 403 including, in some cases, components necessary for coal-based power plant CCS applications. AES’s coal-fired Warrior Run (Cumberland, MD) and Shady Point (Panama, OK) power plants are equipped with amine scrubbers developed by ABB/Lummus. They were designed to process a slip stream of each plant’s flue gas. At Warrior Run, approximately 110,000 metric tons of CO 2 per year are captured, whereas at Shady Point 66,000 metric tons of CO 2 per year are captured. The CO 2 from both plants is subsequently used in the food processing industry. 179 At the Searles Valley Minerals soda ash plant in Trona, CA, approximately 270,000 metric tons of CO 2 per year are captured from the flue gas of a coal-fired power plant via amine scrubbing and used for the carbonation of brine in the process of producing soda ash. 180 A pre-combustion Rectisol® system is used for CO 2 capture at the Dakota Gasification Company’s synthetic natural gas production plant located in North Dakota, which is designed to remove approximately 1.6 million metric tons of CO 2 per year from the synthesis gas. The CO 2 is purified, transported via a 200-

179 Dooley, J. J., et al. (2009). An Assessment of the Commercial Availability of Carbon Dioxide Capture and Storage Technologies as of June 2009. U.S. DOE, Pacific Northwest National Laboratory, under Contract DE-AC05-76RL01830. 180 IEA (2009a), World Energy Outlook 2009, OECD/IEA, Paris.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 217 of 403 mile pipeline for use in EOR operations in the Weyburn oilfield in Saskatchewan, Canada. In September 2009, American Electric Power Co. (AEP) began a pilot-scale CCS demonstration at its Mountaineer Plant in New Haven, WV. The Mountaineer Plant is a 1,300 MWe coal-fired unit that was retrofitted with Alstom’s patented chilled ammonia CO 2 capture technology on a 20 MWe slip stream of the plant’s exhaust flue gas. In May 2011, Alstom Power announced the successful operation of the chilled-ammonia CCS validation project. The demonstration achieved capture rates from 75 percent (design value) to as high as 90 percent, produced CO 2 at purity of greater than 99 percent, with energy penalties within a few percent of predictions. The facility reported robust steady-state operation during all modes of power plant operation including load changes, and saw an availability of the CCS system of greater than 90 percent. AEP, with assistance from the DOE, had planned to expand the slip stream demonstration to a commercial scale, fully integrated demonstration at the Mountaineer facility. The commercial-scale system was designed to capture at least 90 percent of the CO 2 from 235 MW of the plant's 1,300 MW total capacity. Plans were for the project to be completed in four phases, with the system to begin commercial operation in 2015.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 218 of 403 However, in July 2011, AEP announced that it would terminate its cooperative agreement with the DOE and place its plans to

advance CO 2 capture and storage technology to commercial scale on hold, citing the uncertain status of U.S. climate policy as a

contributor to the decision. Oxy-combustion of coal is being demonstrated in a 10 MWe facility in Germany. The Vattenfall plant in eastern Germany (Schwarze Pumpe) has been operating since September 2008. It is designed to capture 70,000 metric tons of CO 2 per year. A larger scale project is in advanced stages of planning in the U.S. In June 2011, Mitsubishi Heavy Industries, an equipment manufacturer, announced the successful launch of operations at a 25 MW coal-fired carbon capture facility at Southern Company's Alabama Power Plant Barry. The demonstration captures approximately 165,000 metric tons of CO 2 annually at a CO 2 capture rate of over 90 percent. The captured CO 2 is being permanently stored underground in a deep saline geologic

formation. Southern Company has begun construction of Mississippi Power Kemper County Energy Facility. This is a 582 MW IGCC plantthat will utilize local Mississippi lignite and include precombustion carbon capture to reduce CO 2 emissions by 65 percent. The captured CO 2 will be used for enhanced oil recovery (EOR) in Comment [A89]: Any 2013 update?

Comment [A90]: Are there any further details that can be added?***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 219 of 403 the Heidelberg Oil Fields in Jasper County, MS. The project is now more than 75 percent complete with start-up and operation expected to begin in 2014. The Texas Clean Energy Project, a 400 MW IGCC facility located near Odessa, Texas will capture 90 percent of its CO 2 , which is approximately 3 million metric tons annually. The captured CO 2 will be used for EOR in the West Texas Permian Basin. Additionally, the plant will produce urea and smaller quantities of commercial-grade sulfuric acid, argon, and inert slag, all of which will also be marketed. The developer expects financing to be fully arranged in 2013. There are other CCS projects – domestic and worldwide -- that are helping to further develop the CCS technology. They are noted in the DOE/NETL’s Carbon Capture, Utilization, and Storage (CCUS) Database. 181 The database includes active, proposed, canceled, and terminated CCUS projects worldwide.

F. Costs As noted, according to the D.C. Circuit case law, control

181 Available at http://www.netl.doe.gov/technologies/carbon_seq/global/database/ Information in the database regarding technologies being developed for capture, evaluation of sites for carbon dioxide (CO 2 ) storage, estimation of project costs, and anticipated dates of completion is sourced from publically available information. The CCUS Database provides the public with information regarding efforts by various industries, public groups, and governments towards development and eventual deployment of CCUS technology.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 220 of 403 costs are considered acceptable as long as they are reasonable, meaning that such costs can be accommodated by the industry. 182 To determine reasonableness, the Court has looked to the amount of the control costs, whether they could be passed on to the consumer, and how much they would lead prices to increase. As we discuss below, where EOR opportunities are available, the sale of captured CO 2 offers the opportunity to defray much of the costs. However, we recognize that there are places where opportunities to sell captured CO 2 for utilization in EOR operations may not be presently available. Nevertheless, as discussed below, our analysis shows that this cost structure –

with and without EOR - is consistent with the D.C. Circuit’s criteria for determining that costs are reasonable. The costs of coal-fired electricity generation – even when not incorporating CCS technology – are high when compared to the current costs of new NGCC generation. Even so, some utilities and other project developers have indicated a willingness and desire to proceed with new fossil fuel-fired boilers and IGCC units. They have indicated the need for energy and fueldiversity. They have also indicated a skepticism regarding longterm projections for low natural gas prices and high

182 In addition, the EPA may consider costs through a national lens, as discussed below. Comment [A91]: Earlier in the rule, EPA states that it will refer throughout the rule to the test as “unreasonable”. Consider using “not unreasonable” here to align with that discussion. See p. 161: i n this rulemaking, we will use the “unreasonable” formulation, so that a control technology cannot be considered the “best system of emission reduction ... adequately demonstrated” if its costs are “unreasonable.”

Comment [A92]: And other generation, yes? Can nuclear or wind also be mentioned here?***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 221 of 403 availability. And there may be other reasons why developers choose to build new coal-fired plants. For these reasons, we believe that these developers have indicated a willingness to proceed with non-NGCC projects, even if they currently do not appear to be the most economic choice. 1. Cost estimates for implementation of partial CCS The EPA has examined costs of new power generation options. These options are shown in Table 4. The table shows the costs of new NGCC technology at two different natural gas prices – at $5/MMBtu, which is reasonably consistent with current and projected prices – and at $10/MMBtu, which would be well above current and projected natural gas prices. We also show costs for SCPC and IGCC units with no CCS (i.e., units that would not meet the proposed emission standard) and those units with partial capture CCS installed such that their emission would meet the proposed 1,100 lb CO 2 /MWh standard. We have also included costs for those units when EOR opportunities are available. We have included a “low EOR” case assuming a low EOR price of $20 per

ton of CO 2 plus the cost for transportation, storage and monitoring (TSM) costs, and a “high EOR” of $40/ton plus the cost for TSM. We also show the projected costs for implementation of full capture CCS (i.e., 90 percent capture). **Table 4. Levelized Cost of Electricity for Electric Generating Technologies, Excluding Transmission Costs**  Comment [A93]: Probably worth a footnote explaining that this does not include savings from direct subsidies like tax credits.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 222 of 403

**Technology Cost of**  **Electricity ($2011/MWh)**  **183,** 184 NGCC @ $5.0/MMBtu 52 NGCC @ $10.0/MMBtu 86

SCPC w/o CCS 185 92 SCPC (1,100 lb/MWh; no EOR) 110 SCPC (1,100 lb/MWh; low EOR) 96 SCPC (1,100 lb/MWh; high EOR) 88 SCPC (full, 90 percent CCS) 147

IGCC w/o CCS 97 IGCC (1,100 lb/MWh; no EOR) 109 IGCC (1,100 lb/MWh; low EOR) 101

183 Data for fossil fuel-fired generation comes from DOE/NETL: (1) Cost and Performance Baseline for Fossil Energy Plants Volume 1: Bituminous Coal and Natural Gas to Electricity, Rev 2, DOE/NELT-2010/1397 (Nov 2010); (2) Updated Costs (June 2011Basis) for Selected Bituminous Baseline Cases” DOE/NETL341/082312 (Aug 2012); (3) Cost and Performance of PC and IGCC Plants for a Range of Carbon Dioxide Capture, DOE/NETL-2011/1498 (May 2011).; Data for non-fossil fuel-fired generation comes from EIA AEO 2013 LCOE estimates from http://www.eia.gov/forecasts/aeo/electricity_generation.cfm ; EIA estimates provided in this table do not include transmission investment to maintain consistency with DOE/NETL estimates. 184 LCOE point estimates are provided for coal-fired capacity types; all other LCOE estimates are presented as a range that reflects EIA’s view on the regional variation in local labor markets, cost and availability of fuel, and renewable resources. The capacity factor ranges for renewable non-dispatchable technologies are as follows: Wind – 30% to 39%, Wind Offshore – 33% to 42%, Solar PV- 22% to 32%, and Solar Thermal – 11% to 26%. Capacity factors for dispatchable are technologies are as follows: Coal – 85%, Nuclear – 90%, Biomass – 83%, Geothermal – 92%, and Combustion Turbine – 30%. There is no capacity credit provided to dispatchable resources. 185 SCPC LCOE includes a 3% increase to the weighted average cost of capital to reflect EIA’s climate uncertainty adder (CUA).***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 223 of 403 IGCC (1,100 lb/MWh; high EOR) 9 7 IGCC (full, 90 percent CCS) 136

Nuclear 103 - 114 Biomass 97 - 130 Geothermal 80 – 99 Combustion Turbine 87 – 116 Onshore Wind 70 – 97 Offshore Wind 177 – 289 Solar PV 186 109 – 220 Solar Thermal 184 – 412

It is important to note here that both the EIA and the EPA apply a climate uncertainty adder (CUA) - represented by a three percent increase to the weighted average cost of capital - to certain coal-fired capacity types. The EIA developed the CUA to address the disconnect between power sector modeling absent GHG regulation and the widespread use of a cost of CO 2 emissions in power sector resource planning. The CUA reflects the additional planning cost typically assigned by project developers and utilities to GHG-intensive projects in a context of climate uncertainty. The EPA believes the CUA is consistent with the industry’s planning and evaluation framework (demonstrable through IRPs and PUC orders) and is therefore necessary to adopt in evaluating the cost competitiveness of alternative generating technologies.

186 Costs are expressed in terms of net AC power available to the grid for the installed capacity. Comment [A94]: This may benefit an explanation of why this uncertainty will still exist after this new source rulemaking (new sources will someday be subject to different standards, whether it’s existing source standards after the 8-yr review or a potentially new legislative regime).***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 224 of 403 EPA believes the CUA is relevant in considering the range of costs that power companies are willing to pay for generation alternatives to natural gas. To the extent that a handful of project developers are still considering coal without CCS, EPA believes they must fall into one of two classes. Either they are not factoring in any form of a CUA. In this case, based both on the analysis EIA undertook in developing the CUA approach and EPA’s review of IRP’s, companies that do this appear to be outliers. In other words, it appears that most companies in fact would not assume the costs without the CUA represents the potential cost (with risk) they would assign to a coal without CCS project. If they are, however, factoring in risk associated with carbon, that suggests they are, in fact, willing to pay the higher cost for coal without CCS (even if they are not actually incurring those costs today). For these reasons, EPA believes that it is appropriate not to give large

consideration to the cost of coal without CCS and without the CUA in the range of costs that utilities are willing to pay for alternatives to natural gas. The EPA is requesting comment on both the CUA’s magnitude and technology-specific application with the intent of ensuring that the EPA’s supporting analysis best reflects the current standards and practices of the power sector’s long-term planning***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 225 of 403

process. 2. Comparison with the costs of other new power generation options While new coal-fired generation that includes CCS is more expensive than either new coal-fired generation without CCS or new NGCC generation, it is competitive with new nuclear power, which is one of the other options often considered for providing new baseload power, and other low-GHG emitting generation technologies. A review of utility IRPs shows that a number of companies are considering new nuclear power as an option for new baseload generation capacity in lieu of new coal-firedgeneration with or without CCS, because they state it is a costeffective way to generate baseload electricity that addresses risks associated with potential future carbon liabilities. New fossil fuel-fired generation that includes CCS serves the same basic function as new nuclear power: providing baseload power with a lower carbon footprint. New coal-fired generation that incorporates partial CCS that is sufficient to meet the CO 2 emission limitation that we are proposing in today’s action (1,100 lb CO 2 /MWh) would have a similar LCOE as a new nuclear power plant (about $103/MWh - $114/MWh). This indicates that, at the proposed emission limitation of 1,100 lb CO 2 /MWh, the cost of new coal-fired generation that includes CCS is reasonable today. Comment [A95]: In light of Fukushima, is this still accurate? Consider adding a footnote to acknowledge Fukushima context.

Comment [A96]: Not unreasonable? in this rulemaking, we will use the “unreasonable” formulation, so that a control technology cannot be considered the “best system of emission reduction ... adequately demonstrated” if its costs are “unreasonable.”***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 226 of 403

3. Costs of “Full capture” CCS As discussed in the Regulatory Impact Analysis (RIA) 187 for this rulemaking, implementation of CCS to achieve 90 percent CO 2 capture adds considerably to the levelized cost of electricity (LCOE) from a new SCPC or IGCC unit. The LCOE for a new SCPC and a new IGCC, both without CCS, are estimated to be $92/MWh and $97/MWh, respectively. The corresponding costs with implementation of “full capture” CCS are $147/MWh for the new SCPC unit and $136/MWh for the new IGCC unit. These costs exceed what project developers have been willing to pay for other low GHG-emitting baseload generating technologies (e.g., nuclear) that also provide energy diversity. For that reason, we do not believe that the costs of full implementation of CCS are

reasonable at this time. 4. Reasonableness of costs of partial CCS As noted, the current costs of coal, natural gas, and construction of coal-fired or natural gas-fired EGUs have led to little currently announced or projected new coal-fired generating capacity. This very likely reflects the large price differential between the cost of a new NGCC (cost of

187 Regulatory Impact Analysis for the Standards of Performance for Greenhouse Gas Emissions for New Fossil Fuel-Fired Electric Utility Steam Generating Units and Stationary Combustion Turbines (available in the rulemaking docket EPA-HQ-OAR-2013- 0495)***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 227 of 403 electricity: $52/MWh at a natural gas price of $5/MMBtu) and SCPC without CCS (cost of electricity: $92/MWh) and IGCC without CCS (cost of electricity: $97/MWh), coupled with a leveling of demand for electricity and the recent increase in renewable

sources. We observe that most of the industry appears to take the view that the price of natural gas will remain sufficiently low for at least a long enough period into the future that new natural-gas fired electricity generation will be less expensive than new coal-fired generation. As a result, in most cases, customers or utilities that contract for new generation are doing so for natural gas-fired generation. Long-term contracts for electricity supply are commonly for a 25-year period; thus, most of the industry appears to consider contracting for new natural gas-fired generation for a 25-year period to be the most

economical of their choices. As shown in Table 4, we estimate that a new SCPC plant costs $92/MWh, which is $40/MWh, or about 77 percent higher than the new NGCC cost of $52/MWh. Limiting the emission rate to 1,100 lb CO 2 /MWh (which can be achieved by adding partial CCS), without sale of captured CO 2 for EOR, would add another $18/MWh to the cost of electricity, for a total of $110/MWh. Thus, the total additional cost to meet the proposed standard by***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 228 of 403 implementing partial capture CCS (without revenues from CO 2 sales for EOR) is about half the additional cost of coal-fired generation, compared to natural-gas fired generation. We are aware of another segment of the industry, which includes electricity suppliers who have indicated a preference for new coal-fired generation to establish or maintain fuel diversity in their generation portfolio because their customers have expressed a willingness to pay a premium for that diversity. It appears these utilities and project developers see lower risks to long-term reliance on coal-fired generation and greater risks to long-term reliance on natural gas-fired generation, compared to the rest of the industry. We consider the costs of CCS to be reasonable for this segment of the industry as well. The additional costs of CCS for new SCPC of $18/MWh LCOE ($110/MWh for SCPC with partial CCS compared to $92/MWh for SCPC without CCS) are only about half as much as the additional costs that are would already need to be incurred to develop coal-fired electricity as compared to new NGCC generation ($92 MWH for SCPC without CCS compared to $52 MWh for NGCC at a natural gas price of $5/MMBtu). Moreover, it is possible that under these circumstances, the demand for the electricity would be inelastic with respect to the price because it may not depend on cost as much as on a demand for energy***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 229 of 403 diversity. These circumstances would be similar to the Portland

Cement (1975) case, discussed above, in which the D.C. Circuit upheld NSPS controls that increased capital and operating costs by a substantial percentage because the demand for the goods was inelastic with respect to price, so that the industry could pass along the costs. 188 In addition, we consider the costs of partial CCS to be reasonable because the industry can accommodate them. As noted, a segment of the industry consists of the several coal-fired EGU projects that already incorporate at least partial CCS. These projects, which are each progressing, include Kemper, TCEP, and HECA. Each is an IGCC plant that expects to generate profits from the sale of products that result from coal gasification, in addition to the sale of electricity. It is true that each of these projects has received DOE grants to encourage the development of CCS technology, but we do not consider such government subsidies to mean that the costs of CCS would otherwise be unreasonable. As we noted in the original proposal for this rulemaking, 189 many types of electricity generation receive government subsidies. For example, nuclear power is the beneficiary of the Price-Anderson Act, which partially

188 Portland Cement Ass’n v. EPA , 513 F.2d 506, 508 (D.C. Cir. 1975). 189 77 Fed. Reg. at 22,418/3.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 230 of 403 indemnifies nuclear power plants against liability claims arising from nuclear incidents, 190 and domestic oil and gas production, 191 coal exploration and development, 192 and renewable energy generation 193 are each the beneficiary of Federal tax

incentives. 5. Opportunities to further reduce the costs of partial CCS a. Enhanced oil recovery While the reasons noted above are sufficient to justify the reasonableness of the costs of partial CCS, there are other

reasons that lead to the same conclusion. One reason is the availability of EOR. As noted, EOR is being actively used in counties in various places in the U.S., and CO 2 pipelines extend into those counties from, in some cases, hundreds of miles away. We consider areas in close proximity to active EOR locations, including the pipelines that extend into those locations, to be places where EOR is available. We recognize that, at present, certain locations are far enough away from either oilfields with EOR availability or

190 See Duke Power Co. v. Carolina Environmental Study Group, 438 U.S. 59 (1978). 191 See, e.g., Internal Revenue Code §263. 192 See, e.g., “General Explanations of the Administration’s Fiscal Year 2013 Revenue Proposals,” pp. 120-24http://www.treasury.gov/resource-center/taxpolicy/Documents/General-Explanations-FY2013.pdf 193 See, e.g., Internal Revenue Code §45. Comment [A97]: Is there a reference that could be used here to show existing subsidies. It appears this citation is about proposals.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 231 of 403 pipelines to those oil fields that any coal-fired power plants

that build in those locations would incur costs to build pipeline extensions that may render EOR non-economical. Those locations are relatively limited when legal or practical limits on building coal-fired power plants are taken into account. For example, some states with locations that are not located near EOR availability are not expected to have new coal-fired builds without CCS in any event, for legal or practical reasons. A number of States including: California, Washington, Oregon and New York preclude new coal-fired power plants without CCS. In the short term, other areas already have high reserve margins and/or have large renewable targets which push new decisions towards renewables and quick starting natural gas to provide backup to renewables over coal fired generation. In addition, it is important to note that coal-fired power plants that build in any particular location may serve demand in a wide area. There are many examples where coal-fired power generated in one state is used to supply electricity in other states. For instance, historically, nearly 40 percent of thepower for the City of Los Angeles was provided from two coalfired power plants located in Arizona and Utah. In another example, Idaho Power, which serves customers in Idaho and Eastern Oregon, meets its demand in part from coal-fired power***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 232 of 403 plants located in Wyoming and Nevada. As a result, the geographic scope of areas in which EOR is available to defray the costs of CCS should be considered to be large. The costs provided in Table 4 show how the ability to

sell CO 2 for utilization in EOR can significantly affect the overall costs of the project.

b. Government subsidies In some instances, the costs of CCS can be defrayed by grants or other benefits provided by the DOE or the states. Although, for the reasons noted earlier, we consider the current costs of CCS even without subsidization to be reasonable, the availability of these governmental subsidies confirms the

reasonableness of the costs. The 2010 Interagency Task Force Report on CCS report described the DOE program as follows: The DOE is currently pursuing multiple demonstration projects using $3.4 billion of available budgetary resources from the American Recovery and Reinvestment Act in addition to prior year appropriations. Up to ten integrated CCS demonstration projects supported by DOE are intended to begin operation by 2016 in the United States. These demonstrations will integrate current CCS technologies with commercial-scale power and industrial plants to prove that they can be permitted and operated safely and reliably. New power plant applications will focus on integrating pre-combustion CO 2 capture, transport, and storage with IGCC technology. Power plant retrofit and industrial applications will demonstrate Comment [A98]: Not unreasonable? in this rulemaking, we will use the “unreasonable” formulation, so that a control technology cannot be considered the “best system of emission reduction ... adequately demonstrated” if its costs are “unreasonable.” Comment [A99]: How so? Because the overall economic impacts are more manageable on consumers? This seems like an incomplete explanation.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 233 of 403 integrated post-combustion capture. 194

DOE allocated some $3.4 billion for 5-10 projects, and has committed $2.2 billion for 5 projects to date. In addition,

various other federal and state incentives are also available to many projects. The 2010 Interagency Task Force on CCS, in surveying all of the federal and state benefits available, concluded that the DOE grants, “plus ... federal loan guarantees, tax incentives, and state-level drivers, cover a large group of potential CCS options.” 195 In addition, regulatory programs may serve to defray the costs of CCS, including, for example, Clean Energy Standards or guaranteed electricity purchase price agreements. 196 As noted above and in the April 2012 proposal, the need for subsidies to support emerging energy systems and new control technologies is not unusual. Each of the major types of energy used to generate electricity has been or is currently being supported by some type of government subsidy such as tax benefits, loan guarantees, low-cost leases, or direct expenditures for some aspect of development and utilization,

194 Task Force Report on CCS, p. 76 195 Task Force Report on CCS, p. 76 196 See Center for Climate and Energy Solutions, “Financial Incentives for CCS” - http://www.c2es.org/sites/default/modules/usmap/pdf.php?file=838 0. Comment [A100]: Please elaborate further on these elements. More information should be provided.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 234 of 403 ranging from exploration to control installation. This is true for fossil fuel-fired; as well as nuclear-, geothermal-, wind-, and solar-generated electricity. 197 c. The costs of CCS are expected to decrease The EPA reasonably projects that the costs of CCS will decrease over time as the technology becomes more widely used. Although, for the reasons noted earlier, we consider the current costs of CCS to be reasonable, the projected decrease in those

costs further confirms their reasonableness. The D.C. Circuit case law that authorizes determining the “best” available technology on the basis of reasonable future projections supports taking into account projected cost reductions as a way

to confirm the reasonableness of the costs. As noted above, the D.C. Circuit, in the 1973 Portland

Cement Ass’n v. Ruckelshaus case, stated that the EPA, in identifying the “best system of emission reduction ... adequately demonstrated,” may “look[] toward what may fairly be projected for the regulated future, rather than the state of the art at

present....” 198 In the 1999 Lignite Energy Council v. EPA case, the

Court elaborated:

197 77 Fed. Reg. at 22,418/3. 198 Portland Cement Ass’n v.Ruckelshaus , 486 F.2d 375, 391 (D.C. Cir. 1973), quoted in Lignite Energy Council v. EPA , 198 F.3d 930, 933-34 (D.C. Cir. 1999). Comment [A101]: Not unreasonable? in this rulemaking, we will use the “unreasonable” formulation, so that a control technology cannot be considered the “best system of emission reduction ... adequately demonstrated” if its costs are “unreasonable.”***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 235 of 403 Of course, where data are unavailable, EPA may not base its determination that a technology is adequately demonstrated or that a standard is achievable on mere speculation or conjecture....but EPA may compensate for a shortage of data through the use of other qualitative methods, including the reasonable extrapolation of a technology's performance in other industries. 199

It is logical to read these statements in the D.C. Circuit case law to apply as well to the cost component of the “best system of emission reduction ... adequately demonstrated.” We expect the costs of CCS technologies to decrease

. for

several reasons. We expect that significant additional knowledge will be gained from deployment and operation of at least two new coal-fired generation projects that include CCS. These projects (the Southern Company’s Kemper County Energy Facility IGCC withCCS and the Boundary Dam CCS project on a conventional coalfired power plant in Canada) are currently under construction and are expected to commence operation next year. In addition there are several other CCS projects in advanced stages of development in the U.S. (e.g., the Texas Clean Energy Project, the Hydrogen Energy California Project, and the Future Gen

199 Lignite Energy Council v. EPA , 198 F.3d 930, 934 (D.C. Cir. 1999). Based on this view that EPA may extrapolate from other industries, the Court in the Lignite Energy Council v. EPA case upheld a control technology as being “adequately demonstrated” for coal-fired industrial boilers because the technology was utilized by utility boilers. Comment [A102]: Any citations to provide further support?***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 236 of 403 project in Illinois) that may also provide additional information. In addition, research is underway to reduce CO 2 capture costs and to improve performance. The DOE/NETL sponsors an extensive research, development and demonstration program that is focused on developing advanced technology options that will dramatically lower the cost of capturing CO 2 from fossilfuel energy plants compared to today’s available capture technologies. The DOE/NETL estimates that using today’s available CCS technologies would add around 80 percent to the cost of electricity for a new pulverized coal plant, and around 35 percent to the cost of electricity for a new advanced gasification-based plant (Note that these cost increases would be significantly less for the partial capture standard being proposed in today’s notice). The CCS research, development and demonstration program is aggressively pursuing efforts to reduce these costs to a less than 30 percent increase in the cost of electricity for PC power plants and a less than 10 percent increase in the cost of electricity for new gasification-based power plants. 200 The large-scale CO 2 capture demonstrations that are currently planned and in some cases underway, under the DOE’s initiatives, as well as other domestic and international

200 DOE/NETL Carbon Dioxide Capture and Storage RD&D Roadmap, U.S. Department of Energy National Energy Technology Laboratory, December 2010.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 237 of 403 projects, will generate operational knowledge and enable continued commercialization and deployment of these technologies. Gas absorption processes using chemical solvents, such as amines, to separate CO 2 from other gases have been in use since the 1930s in the natural gas industry and to produce food and chemical grade CO 2 . The advancement of amine-based solvents is an example of technology development that has improved the cost and performance of CO 2 capture. Most single component amine systems are not practical in a flue gas environment as the amine will rapidly degrade in the presence of oxygen and other

contaminants. The Fluor Econamine FG SM process uses a monoethanolamine (MEA) formulation specially designed to recover

CO 2 and contains a corrosion inhibitor that allows the use of less expensive, conventional materials of construction. Other commercially available processes use sterically hindered amine formulations (for example, the Mitsubishi Heavy Industries KS-1 solvent) which are less susceptible to degradation and corrosion issues. The DOE/NETL and private industry are continuing to sponsor research on advanced solvents (including new classes of amines) to improve the CO 2 capture performance and reduce costs. Significant reductions in the cost of CO 2 capture would be consistent with overall experience with the cost of pollution***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 238 of 403 control technology. A significant body of literature suggests that the per-unit cost of producing or using a given technology declines as experience with that technology increases over time, 201 and this has certainly been the case with air pollution control technologies. Reductions in the cost of air pollution control technologies as a result of learning-by-doing, reductions in financial premiums related to risk, research and development investments, and other factors have been observed

over the decades. In addition, we note that the 2010 Interagency Task Force on CCS report recognized that CCS would not become more widely available without a regulatory framework that promoted CCS or a strong price signal for CO 2 . Today’s action is an important component in developing that framework. G. Promotion of technology

201 These studies include John M. Dutton and Annie Thomas, "Treating Progress Functions as a Managerial Opportunity," 2, 235-247; Dennis Epple, Linda Argote, and Rukmini Devadas, "Organizational Learning Curves: A Method for Investigating Intra-plant Transfer of Knowledge Acquired Through Learning by Doing," Organizational Science, Vol. 2, No. 1, February 1991; International Energy Agency, Experience Curves for Energy Technology Policy, 2000; and Paul L. Joskow and Nancy L. Rose, "The Effects of Technological Change, Experience, andEnvironmental Regulation on the Construction Cost of CoalBurning Generating Units," RAND Journal of Economics, Vol. 16,Issue 1, 1-27, 1985. See discussion in “The Benefits and Costs of the Clean Air Act from 1990 to 2020,” U.S. EPA, Office of Air and Radiation, April 2011. Comment [A103]: It would be helpful to cite relevant literature to support the statement.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 239 of 403 It is clear that identifying partial CCS as the BSERpromotes the utilization of CCS because any new fossil fuelfired utilty boiler or IGCC unit will need to install partial capture CCS in order to meet the emission standard. Particularly because the technology is relatively new, additional utilization is expected to result in improvements in the performance technology and in cost reductions. Moreover, identifying partial capture CCS as the BSER will encourage continued research and development efforts, such as those sponsored by the DOE/NETL. In contrast, not identifying partial CCS as the BSER could potentially impede further utilization and development of CCS. It is important to promote deployment and further development of CCS technologies because they are the only technologies that are currently available or are expected to be available in the foreseeable future that can make meaningful reductions in CO 2 emissions from fossil fuel-fired utility boilers and IGCC units. Identifying partial CCS as the BSER also promotes further use of EOR because, as a practical matter, we expect that new fossil fuel-fired EGUs that install CCS will generally make the captured CO 2 available for use in EOR operations. The use of EOR lowers costs for production of domestic oil, which promotes the important goal of energy independence. H. Nationwide, longer-term perspective***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 240 of 403 As noted, the D.C. Circuit in Sierra Club held: The language of [the definition of “standard of performance” in] section 111 ... gives EPA authority when determining the best ... system to weigh cost, energy, and environmental impacts in the broadest sense at the national and regional levels and over time as opposed to simply at the plant level in the immediate present. 202

Considering on “the national and regional levels and over time” the criteria that go into determining the “best system of emission reduction ... adequately demonstrated” also supports identifying partial CCS as that best system because doing so would not have adverse impacts on the power sector, national electricity prices, or the energy sector. 1. Structure of the power sectorIdentifying partial CCS as the BSER for new fossil fuelfired utility boilers and IGCC units is consistent with the current and projected future structure of the power sector. As noted, we project that in light of the current and projected trends in coal and natural gas costs, virtually all new electric generating capacity will employ NGCC technology or renewable energy, and very little new capacity will be coal-fired.As noted above, the recent history of solid fossil fuelfired projects suggest that these new coal-fired builds, if they

202 Sierra Club v. Costle , 657 F.2d at 330.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 241 of 403 occur, may (i) consist of an IGCC unit, include features such as sale of additional byproducts (e.g., plants such as the Texas Clean Energy Project, which intents to manufacture fertilizer products for sale and sell captured CO 2 for EOR in addition to selling electricity), use of lower cost opportunity fuels (such as petcoke proposed to be used at the Hydrogen Energy California facility) and/or rely on additional local regulatory drivers (such as California’s AB-32 program which incentivizes lower CO 2 generating technologies), all of which would be designed to offset enough of the additional coal-related costs to be able to compete with natural-gas fired electricity in the marketplace; and (ii) those that are designed to offer fuel diversity to a group of customers that are willing to pay a premium in electricity prices (such as the Power4Georgians project in Washington County, Georgia). Projects in the first category would by definition already include at least partial CCS and, as a result, would be affected by this rule to only a limited extent. Projects in the second category would be more affected, but developers of these projects would nevertheless have several options. They could pursue coal with CCS and possibly rely on cost savings from EOR or on their customers’ willingness to pay a higher premium. Alternatively, they could choose a different generation***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 242 of 403 technology (most likely natural gas). Even if they chose a different generation technology, the small number of these sources and the fact that the basic demand for electricity would still be met would limit the impact of this rule on the power

sector. 2. Impacts on nationwide electricity prices. Identifying partial CCS as the BSER for fossil fuel-fired utility boilers and IGCC units will not have significant impacts on nationwide electricity prices. The reason is that the additional costs of partial CCS will, on a nationwide basis, be small because no more than a few new coal-fired projects are expected, and because, as noted, at least some of these can be expected to incorporate CCS technology in any event. It should be noted that the computerized model the EPA relies on to assess energy sector and nationwide impacts – the Integrated Planing Model (IPM) – does not forecast any new coal-fired EGUs through 2020. Based on these IPM analyses, the RIA for this rulemaking concludes that the proposed standard of 1,100 lb of CO 2 /MWh for new fossil fuel-fired EGUs, which is based on partial CCS as the best demonstrated system, does not create any costs. 3. Energy considerationsIdentifying partial CCS as the BSER for new fossil fuelfired utility boilers and IGCC units is consistent with Comment [A104]: EPA may want to consider pointing out in this section that the availability of natural gas-fired plants to meet electricity generation needs at a reasonable cost also serves as a backstop against any large economic/energy impacts.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 243 of 403 nationwide energy considerations because it will not have adverse effects on the structure of the power sector, will promote fuel diversity over the long term, and will not have adverse effects on the supply of electricity. Identifying partial CCS as the BSER will not have adverse impacts on the structure of the power sector because, as noted,

for reasons related to the cost differential between natural gas-fired and coal-fired electricity, very little, if any, new coal-fired EGUs are projected to be built, and at least some of those that may be built would be expected to include CCS technology in any event. In addition, identifying partial CCS as the BSER for coal will be beneficial to coal-fired electric generation, and therefore fuel diversity, over the long term. This is because Identifying i I dentifying partial CCS as BSER eliminates uncertainty as to future control obligations for coal-fired capacity. Any Currently, any new coal-fired source that

constructs without CCS faces the risk that future state or federal controls may require carbon capture, which would require

the source to retrofit to CCS, which, in turn, is a particularly

more expensive proposition. This risk is heightened because power plants are generally long-lived and the risk likelihood of future carbon limitations can be expected to remain throughout***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 244 of 403 that period. Any new coal-fired source that constructs with partial-capture CCS will achieve some level of CO 2 emissions reductions, which lowers the risk of future liability

. , which and may provide competitive advantages over higher emitting sources. Because at present, new electric generating construction is primarily natural gas-fired, benefiting new coal-fired capacity, at least over the long term, protects fuel diversity. Moreover, even if requiring CCS adds sufficient costs to prevent a new coal-fired plants from constructing in a particular part of the country due to lack of available EOR to defray the costs, or, in fact, from constructing at all, a new NGCC plant can be built to serve the electricity demand that the coal-fired plant would otherwise serve. Thus, the present rulemaking does not prevent basic electricity demand from being met, and thus does not have an adverse effect on the supply of electricity. As noted above, the EPA is authorized to promulgate standards of performance under CAA §111 that may have the effect of precluding construction of sources in certain geographic

locations or in certain locations.

4. Environmental considerations Identifying partial CCS as the BSER for coal-fired power plants protects the environment by preventing large amounts of

CO 2 emissions from new fossil fuel-fired utility boilers and IGCC***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 245 of 403 units. As noted, CCS is the only technology available at present or within the foreseeable future that provides meaningful

reductions in the amount of CO 2 emissions in this sector. I. Consistency with purposes of CAA section 111 Identifying partial CCS as the BSER is also consistent with the purposes of CAA section 111, which, as discussed above, including includes avoiding giving any state a competitive advantage, reducing emissions as much as possible, obviating any need for retrofits on new sources, and promoting technology development. 203 One purpose of CAA section 111 is that “[t]he standards [of performance] must not give a competitive advantage to one State over another in attracting industry.” 204 The 1,100 lb CO 2 /MWh standard that the EPA proposes in this rulemaking applies to all new coal-fired power plants in all geographic locations. As a result, there is nothing on the face of the standard that would provide a competitive advantage to one state over another in attracting industry. While it is true that some states may offer more attractive opportunities for CCS – because, for example, of

203 Sierra Club v. Costle , 657 F.2d at 325 & n.83 (quoting 44 Fed.Reg. 33,580, 33,581/3-33,582/1 (EPA summary of the six purposes identified in the 1977 House Committee Report, H.R. Rep. No. 95-294, 95th Cong., 1st Sess. 184-86 (1977), 4 L.H. at 2651-53)). 204 Sierra Club, 657 F.2d at 325 & n. 83.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 246 of 403 greater availability or value for EOR – power plant siting by its nature generally favors certain locations over others. For example, coal-fired power plants usually require a large source of water, which favors certain locations over others. The fact that CCS adds another siting consideration does not mean that it unfairly benefits certain States at the expense of others, so far as the purposes of section 111 are concerned. A second purpose of section 111 is “reducing emissions as much as practicable.” 205 For the reasons noted above, identifying partial CCS as the BSER meets this purpose. A third purpose of section 111 is, “to the extent practical force the installation of all the control technology that will ever be necessary on new plants at the time of construction when it is cheaper to install, thereby minimizing the need for

retrofit in the future....” 206 As noted above, identifying partial CCS as BSER meets this purpose by achieving CO 2 emissions reductions. In contrast, identifying highly efficient SCPC or IGCC without at least partial CCS as the BSER would leave sources vulnerable to retrofit obligations if CO 2 emissions reduction requirements are imposed in the future.

205 Id. As noted, Congress identified this purpose in the context of NAAQS pollutants, but this purpose applies to greenhouse gases as well. 206 Id.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 247 of 403 A fourth purpose of section 111 is “The standards should be stringent in order to force the development of improved technology.” 207 For the reasons noted above, identifying partial CCS as the BSER meets this purpose.

J. Deference As noted above, the D.C. Circuit has held that it will grant a high degree of deference to the EPA in determining the appropriate standard of performance. Because determining the BSER for coal-fired power plants requires balancing several factors, including on a nationwide basis and over time, the EPA’s determination that partial CCS is the BSER should be granted a high degree of deference. K. CCS and BSER in locations where costs are too high to implement CCS As noted above, under CAA §111, an emissions standard may meet the requirements of a “standard of performance” even if it cannot be met by every new source in the source category that

would have constructed in the absence of that standard. As also noted above, the EPA’s analysis for this proposal indicates that coal-fired power plants that would otherwise construct in the absence of the standards in this proposal may still do so. However, we recognize that there may be some geographic

207 Id.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 248 of 403 locations where EOR is not practicably available, so that in those locations, the higher costs of CCS may tilt the economics against new coal-fired construction. Even in this case, the standard would remain valid under CAA §111, particularly because the basic demand for electricity could still be served by NGCC, which this rulemaking determines to be the “best system” for natural gas-fired power plants. L. Compliance period 1. 12-operating-month period Under today’s proposal, sources must meet the 1,100 lb

CO 2 /MWh limit on a 12-operating-month rolling basis. This 12- operating-month period is important due the inherent variability in power plant GHG emissions rates. Establishing a shorter averaging period would necessitate establishing a standard to account for the conditions that result in the lowest efficiency and therefore the highest GHG emissions rate. EGU efficiency has a significant impact on the source’s GHG emission rate. By comparison, efficieny has a smaller impact on the emissions rate for criteria or hazardous air pollutants (HAPs). This is because control of criteria pollutants and HAPs often involves the use of a pollution control device that results in significant reductions, often greater 90 percent. In this situation, the performance of the specific pollution***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 249 of 403 control device impacts the emissions rate much more than the EGU efficiency. In this situation, efficiency is a key factor in determining the emissions rate. EGU efficiency can vary significantly from month to month throughout the year. For example, high ambient temperature can negatively impact the efficiency of combustion turbine engines and steam generating units. As a result, an averaging period shorter than 12 operating-months would require us to set a

standard that could be achieved under these conditions. This standard could potentially be high enough that it would not be a meaningful constraint during other parts of the year. In addition, operation at low load conditions can also negatively impact efficiency. It is likely that for some short period of time an EGU will operate at an unusually low load. A short averaging period that accounts for this operation would again not necessarily meaningfully constrain for typical loads. On the other hand, a 12-operating-month rolling average explicitly accounts for variable operating conditions, allows consistent emissions rate averaging, allows for a more protective standard and decreased compliance burden, and simplifies compliance for state permitting authorities. Because the 12-operating-month rolling average can be calculated each month, this form of standard makes it possible to assess***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 250 of 403 compliance and take any needed corrective action on a monthly basis. The EPA proposes that it is not necessary to have a shorter averaging period for CO 2 from these sources because the effect of GHGs on climate change depends on global atmospheric concentrations which are dependent on cumulative total emissions over time, rather than hourly or daily emissions fluctuations or local pollutant concentrations. Unlike for emissions of criteria and hazardous air pollutants, we do not believe that there are

not measureable implications to health or environmental impacts from short-term higher CO 2 emission rates as long as the 12-month average emissions rate is maintained. We solicit comment on, in the alternative, basing compliance requirements on an annual (calendar year) average

basis. 2. 60-operating-month compliance period compliance period Under today’s proposal, new fossil fuel-fired boilers and IGCC units will have the option to alternatively meet an emission standard on a 60-operating-month rolling basis.The EPA has previously offered sources optional, longerterm emission standards that are stricter than the primary

emissions standard in exchange for the the combination with a longer averaging period. We are proposing that this alternative emission limit should be between 950 – 1,050 lb CO 2 /MWh and we Comment [A105]: Appears this should be omitted.

Comment [A106]: “in exchange for” sounds like a negotiation.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 251 of 403 are requesting comment on what the final numerical standard should be (within that range) such that the 60-operating-month standard would be as stringent as or more stringent than the 12- operating-month standard.We are also request comment on an appropriate 12-operatingmonth standard that owners/operators electing to comply with the 60-operating-month standard would have to comply with. This standard would be numerically between the alternate 12- operating-month standard and an emissions rate of a coal-fired EGU without CCS (e.g., 1,800 lb CO 2 /MWh). This shorter term standard would be more easily enforced and assure adequate

emission reductions. This 60-operating-month period offers increased operational flexibility and will tend to dampen short-term emission excursions, which may be warranted especially at the initial startup of the facility and the CCS system. M. Geologic sequestration

1. Overview We expect that for the immediate future, virtually all of

the CO 2 captured at EGUs will be injected underground for longterm geologic sequestration at sites where enhanced oil recovery is also occurring. There is an existing regulatory framework for geologic sequestration and enhanced oil recovery activities. We***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 252 of 403 intend to rely upon this existing framework to verify that the

CO 2 captured from an affected unit is injected underground for long-term containment. More specifically, as discussed in section 3, the EPA is proposing to build from the existing Greenhouse Gas Reporting Program 40 CFR Part 98 to track that the captured CO 2 is geologically sequestered. In addition, we recognize that types of CO 2 storage technologies other than geologic sequestration are under development (e.g. precipitated calcium carbonate, etc). EGUs may use other types of CO 2 storage technologies to meet the standard, once the EPA has approved its use, including methods for reporting, monitoring, and verifying long-term CO 2 storage. We welcome comments on an appropriate mechanism for making this

determination. 2. Existing regulatory framework for CCS As noted, the EPA expects that for the immediate future, captured CO 2 from affected units will be injected underground for geologic sequestration at sites where EOR is occurring. Underground injection is currently the only technology available that can accommodate the large quantities of CO 2 captured at EGUs, and EOR provides an associated economic incentive and

benefit. The three Tthree solid-fuel fired EGU projects Formatted: Subscript***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 253 of 403 incorporating CCS that have progressed the furthest – Kemper, TCEP, and HECA – all include utilization of captured CO 2 for EOR. The EPA has promulgated, or recently proposed, several rules to protect underground sources of drinking water and track

the total amount of CO 2 that is supplied to the economy and injected underground for geologic sequestration. First, the EPA’s Underground Injection Control (UIC) Class VI rule, established under authority of the Safe Drinking Water Act, sets requirements to ensure that geologic sequestration wells are appropriately sited, constructed, tested, monitored, and closed in a manner that ensures protection of underground sources of drinking water. 208 The UIC Class VI regulations contain monitoring requirements to protect underground sources of drinking water, including the development of a comprehensive testing and monitoring plan. This includes testing of the mechanical integrity of the injection well, ground water monitoring, and tracking of the location of the injected CO 2 and the associated area of elevated pressure using both direct and indirect methods, as appropriate. Projects are also required to conduct extended post-injection monitoring and site care to track the location of the injected CO 2 and monitor subsurface

208 http://water.epa.gov/type/groundwater/uic/wells_sequestration.cf m Comment [A107]: Consider whether this is necessary in the context of describing the existing regulatory framework***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 254 of 403 pressures until it can be demonstrated that there is no longer a risk of endangerment to underground sources of drinking water. UIC Class II wells inject fluids associated with oil and natural gas production and the storage of liquid hydrocarbons. Most of the injected fluid is salt water, which is brought to the surface in the process of producing (extracting) oil and gas and subsequently re-injected. In addition, other fluids, including CO 2 , are injected to enhance oil and gas production. Class II regulations include site characterization, well construction, operating, monitoring, testing, reporting, financial responsibility, and closure requirements to prevent endangerment of underground sources of drinking water. Wells that inject CO 2 underground for enhanced oil or gas recovery may be permitted as UIC Class II or Class VI wells. However, the designation of the appropriate well class depends, principally, on the risks posed or changes in the risks posed to underground sources of drinking water by a specific injection operation. Second, the Greenhouse Gas Reporting Program (GHGRP) covers sources that generate electricity (40 CFR Part 98 subpart D), sources that supply CO 2 to the economy (40 CFR Part 98, subpart PP) and sources that inject CO 2 underground for geologic sequestration (40 CFR Part 98, subpart RR). Subpart D owners or operators of facilities that contain electricity-generating***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 255 of 403 units must report emissions from electricity-generating units and all other source categories located at the facility for

which methods are defined in Part 98. 209 Owners or operators are required to collect emission data; calculate GHG emissions; and follow the specified procedures for quality assurance, missing data, recordkeeping, and reporting. Subpart PP provides requirements for quantifying CO 2 supplied to the economy. 210 Affected units that capture CO 2 to inject underground or supply offsite, are subject to all of the requirements under Subpart PP of the GHG Reporting Program, which relates to suppliers of CO 2 . Specifically, Subpart PP requires suppliers of CO 2 that meet certain applicability requirements to report the mass of CO 2 captured from production process unit(s) for the purposes of supplying CO 2 for commercial applications or that capture and maintain custody of a CO 2 stream in order to sequester or otherwise inject underground. CO 2 suppliers are required to report the annual quantity of

CO 2 transferred CO 2 transferred offsite and for what end use, including geologic sequestration. Subpart RR requires that facilities meeting the source category definition (40 CFR 98.440) for any well or group of

209 http://www.epa.gov/ghgreporting/reporters/subpart/d.html 210 http://www.epa.gov/ghgreporting/reporters/subpart/pp.html***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 256 of 403 wells to report basic information on the amount of CO 2 received for injection; develop and implement an EPA-approved monitoring, reporting, and verification (MRV) plan; and report the amount of

CO 2 sequestered using a mass balance approach and annual monitoring activities. The MRV plan must be submitted and approved by the EPA and revised if necessary over time according to 40 CFR 98.448(d). The subpart RR MRV plan must include five major components:

 A delineation of the maximum monitoring area (MMA) and the active monitoring area (AMA).

 An identification and evaluation of the potential surface leakage pathways and an assessment of the likelihood, magnitude, and timing, of surface leakage of CO 2 through these pathways in the MMA.

 A strategy for detecting and quantifying any surface leakage of CO 2 in the event leakage occurs.

 An approach for establishing the expected baselines for monitoring CO 2 surface leakage.

 A summary of considerations made to calculate site-specific variables for the mass balance equation. More information on the MRV plan is available in the Technical Support Document (TSD) for the subpart RR final rule (75 FR 75065).***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 257 of 403 If an enhanced oil and gas recovery project holds a UIC Class VI permit, it is required to report under subpart RR. If the project holds a UIC Class II permit and is injecting a CO 2 stream underground, it is not subject to subpart RR, but the owner or operator may choose to opt-in to subpart RR. Sources reporting under subpart RR, whether they are UIC Class VI or Class II well(s), must follow the same set of requirements. As stated in the preamble to the final subpart RR rule: “while requirements under the UIC program are focused on demonstrating that USDWs are not endangered as a result of CO 2 injection into the subsurface, requirements under the GHG Reporting Program through 40 CFR part 98, subpart RR will enable EPA to verify the quantity of CO 2 that is geologically sequestered and to assess the efficacy of GS as a mitigation strategy. Subpart RR achieves this by requiring facilities conducting GS to develop and implement a MRV plan to detect and quantify leakage of injected CO 2 to the surface in the event leakage occurs and to report the amount of CO 2 geologically sequestered using a mass balance approach, regardless of the class of UIC permit that a facility holds.” (75 FR 75060)

The Internal Revenue Service relies on subpart RR compliance to verify geologic sequestration for the 45Q tax credit. As stated in the preamble to the final subpart RR

rule:

“EPA notes that the Internal Revenue Service (IRS) published IRS Notice 2009–83 7 to provide guidance regarding eligibility for the Internal Revenue Code section 45Q credit for CO 2 sequestration, computation of the section 45Q tax credit, reporting requirements for taxpayers claiming the section 45Q***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 258 of 403 tax credit, and rules regarding adequate security measures for secure GS. As clarified in the IRS guidance, taxpayers claiming the section 45Q tax credit must follow the appropriate UIC requirements. The guidance also clarifies that taxpayers claiming section 45Q tax credit must follow the MRV procedures that are being finalized under 40 CFR part 98, subpart RR in this final rule.” (75 FR 75060) Third, the EPA proposed a rule that would conditionally

exclude CO 2 streams from the definition of hazardous waste under RCRA, where these streams are being injected for purposes of geologic sequestration, into a UIC Class VI well and meet other

conditions. 211 The rationale for the rule was that any CO 2 stream that would otherwise be defined as hazardous waste, need not be managed as hazardous waste, provided it is managed under other regulatory programs that address the potential risks to human health and the environment that these materials may pose. The EPA notes that compliance with the standard of 1,100 lb

CO 2 /MWh is determined exclusively by the tons of CO 2 captured by the emitting EGU. The tons of CO 2 sequestered by the repository are not part of that calculation. However, to verify the amount

of tons of CO 2 captured at the emitting EGU are safely and effectively sequestered, we are building on existing regulatory requirements under Subpart RR, all CO 2 that is geologically sequestered at the site of the EGU facility must be reported

211 76 Fed. Reg. 48073 (Aug. 8, 2011) Formatted: Subscript***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 259 of 403 under subpart RR by the owner or operator of the EGU. Additionally, where the captured CO 2 is sent offsite, it must be transferred to an entity that is reporting under Subpart RR. This provides assurance that the tons of CO 2 captured are transferred to a repository which provides assurance of long term containment integrity. Under today’s proposal, that type of repository is a Class II or Class VI UIC well which would report its GHG emissions under subpart RR. The EPA acknowledges that there can be downstream losses of

CO 2 after capture. The EPA expects these losses to be modest with

incentives due to the market use of CO 2 as a purchased product.

There remains an issue of whether the standard itself should be adjusted to reflect these downstream losses. The EPA is not proposing to do so. Moreover, the EPA wishes to encourage rather than discourage EOR using captured CO 2 since the practice makes CCS itself more economic and thus promotes use of the technology on which the proposed standard is based. See Sierra Club v.

Costle , 657 F. 2d at 347 (one purpose of section 111 standards is to promote expanded use and development of technology). We also emphasize that today’s proposal does not involve regulation of any downstream recipients of captured CO 2 . That is, the regulatory standard applies exclusively to the emitting EGU, not to any downstream user or recipient of the captured CO 2 Formatted: Subscript

Comment [A108]: How will this requirement be enforced? Is the requirement for CO2 to be reported under the GHG reporting program an explicit part of the “standard of performance” and therefore enforceable like any other part of the standard?

Comment [A109]: At what points can downstream losses occur? Are there multiple? Also, are there any lossess associated with onsite storage?***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 260 of 403 (whether the captured CO 2 is sold for productive use or otherwise managed). The requirement that the emitting entity assure that captured CO 2 is managed at an entity subject to the GHG reporting rules is thus exclusively an element of enforcement of the EGU standard. Similarly, the existing regulatory requirements applicable to geologic sequestration are not part of the proposed NSPS. The standard is a numeric value, applicable exclusively to the emitting EGU. The requirement that the EGU use the repository reporting pursuant to subpart RR and that the repository be a Class II or VI UIC well is a means of assuring the integrity of the stack emission limit applicable to the emitting EGU. 3. Proposal a. Geologic Sequestration Together, the framework just described help create a

consistent national framework to ensure the safe and effective deployment of geologic sequestration technologies. Importantly, a key component of this framework- the Greenhouse Gas Reporting Program- provides a mechanism for new generating units that supply captured CO 2 for geologic sequestration (including CO 2 sequestered while oil and gas recovery is occurring), to help demonstrate they are achieving the required emission reductions. Therefore, the EPA is proposing that any affected unit that Comment [A110]: ?? suggest omitting. Consider rephrasing sentence: The NSPS proposal builds on and is consistent with existing framework for safe and effective GS.

Comment [A111]: Is this potentially overstating the extent of the requirements, given that long term sequestration is not actually part of what’s “required” (just sending the CO2 to a facility that reports)?***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 261 of 403 employs CCS technology which captures enough CO 2 to meet the 1,100 lb/MWh standard must report, under 40 CFR Part 98 Subpart RR, if the captured CO 2 is injected onsite. If the captured CO 2 is sent offsite, then the facility injecting the CO 2 underground must report under 40 CFR Part 98 subpart RR. Regardless of the injection site, the affected source must still comply with 40 CFR Part 98 Subpart PP. As noted above, owners and operators of projects that inject CO 2 underground and that are permitted under a UIC Class VI permit are required to comply with subpart RR. The practical impact of our proposal would be that owners and operators of projects injecting CO 2 underground that are permitted under UIC Class II and that receive CO 2 captured from EGUs to meet the proposed performance standard will also be required to submit and receive approval of a subpart RR MRV plan and report under subpart RR. Many of these EOR facilities are already familiar with reporting under Subpart UU of the Greenhouse Gas Reporting Program. To provide certainty and verify that CO 2 captured at an affected unit is geologically sequestered, today’s action relies upon the existing regulatory framework the EPA already has in place under the Greenhouse Gas Reporting Program 40 CFR Part 98. As discussed in the previous section, there are 3 relevant subparts (subpart D, PP and RR) under 40 CFR Part 98, that can***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 262 of 403 provide an appropriate reporting and verification mechanism for demonstrating that any unit subject to these proposed standards complies with them. The EPA requires electric generating units to report CO 2 emissions under subpart D. Facilities that capture

CO 2 are required to report quantities of CO 2 captured and injected on site or transferred off-site under subpart PP. Facilities that inject CO 2 underground for permanent sequestration report under subpart RR. Through these Greenhouse Gas Reporting Program provisions, the EPA and other regulatory authorities can track geologic sequestration conducted to meet the performance standard. In order to use the GHGRP for compliance tracking, the EPA proposes that any affected unit that uses CCS to comply with the

emissions limit must demonstrate that CO 2 is geologically sequestered through the Greenhouse Gas Reporting Program. In order to do that, we are proposing that a facility capturing CO 2 from an affected unit, and therefore subject to 40 CFR Part 98 subpart PP, must provide additional information in their subpart PP annual report including 1) the electronic Greenhouse Gas Reporting Tool identification (e-GGRT ID) of the facility with the electric generating unit from which CO 2 was captured, 2) the e-GGRT ID(s) for, and mass of CO 2 transferred to, each geologic sequestration site reporting under subpart RR. This proposed Comment [A112]: This seems somewhat unclear. Must the affected unit demonstrate sequestration or just that it goes to a facility that reports under the GHG reporting program? This seems to imply the former, but doesn’t seem consistent with the explanation above.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 263 of 403 amendment to the Greenhouse Gas Reporting Program provides a transparent and consistent method to track geologic sequestration used to meet the performance standard without significantly increasing burden on the affected sources. If the unit does not report under PP and comply with these proposed requirements, it will be considered in noncompliance with today’s proposal. The approach proposed today relies on the existing Greenhouse Gas Reporting framework to ensure that CO 2 captured at an affected unit is transferred to a facility reporting geologic sequestration, and it does not impose any additional requirements for an affected unit to demonstrate how the captured CO 2 is transferred to a facility that is compliant with 40 CFR 98 subpart RR. We seek comment on whether there should be such requirements and suggestions for what those might

include. b. Alternatives to geologic sequestration In the development of this proposal, the EPA has identified some potential alternatives to geologic sequestration, including

but not limited to CO 2 stored in precipitated calcium carbonate and certain types of cement. The EPA solicits comment on whether these and other alternatives to geologic sequestration permanently store CO 2 (so that the stack standard is assured of Comment [A113]: As noted above, this seems to imply that the amount of CO2 sequestered is part of the performance standard, but that doesn’t seem to be consistent with what is explained elsewhere in this section.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 264 of 403 achieving its object—to capture CO 2 and prevent its atmospheric release) and if they are technically available for EGUs to meet the performance standard. Consideration of how these alternatives could meet the performance standard involves understanding the ultimate fate of the captured CO 2 and the degree to which the method permanently isolates the CO 2 from the atmosphere, as well as existing methodologies to verify this permanent storage. The EPA proposes that alternatives to geologic sequestration could not be used until the EPA finalizes a mechanism to demonstrate that a non-CCS technology would result in permanent storage of CO 2 . The EPA believes that the number of cases where an EGU would seek to comply with the performance standard through an alternative to CCS will be very few. However, the EPA wishes to encourage development of alternatives to geologic sequestration that could help offset

the cost of CO 2 capture.

c. Drafting Prevention of Significant Deterioration ( PSD ) permits for affected sources using geologic sequestration In most cases, sources that are subject to this NSPS will also be a major source or major modification under PSD and required to obtain a PSD permit prior to commencing construction. A permit is the legal tool used to establish all the source limitations deemed necessary by the reviewing agency Comment [A114]: Has EPA demonstrated that GS meets this standard?***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 265 of 403 during review of the permit application, and is the primary basis for enforcement of PSD requirements. A well written permit reflects the outcome of the permit review process and clearly defines what is expected of the source. The permit must be a "stand-alone" document that: (1) identifies the emissions units to be regulated; (2) establishes emissions standards or other operational limits to be met; (3) specifies methods for determining compliance and/or excess emissions, including reporting and recordkeeping requirements; and (4) outlines the procedures necessary to maintain continuous compliance with the emission limits. As noted in the "Implications for PSD and Title V programs" section of this preamble, some states have authority to issue PSD permits. In other cases, the EPA issues the permit. States with approved permitting programs have some discretion in making permit decisions and including the necessary conditions of the permit to ensure the enforceability of the permit. Compliance with the NSPS emissions standard is determined exclusively by evaluating emissions of CO 2 at the EGU. To this end, section 60.5520 of this proposed rule, titled “What CO 2 emissions standard must I meet?”, reads: For each affected EGU subject to this subpart, you must not discharge from the EGU into the atmosphere any gases that contain CO 2 in excess of the applicable CO 2 emissions standard specified in Table 1 to this***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 266 of 403 subpart. Each CO 2 emissions standard has a minimum of two significant digits.

T he EPA believes it is important to clarify the key components that should be included in a PSD permit. While we recognize that permit conditions may vary from state to state, we believe the following general condition areas of a permit would adequately show that the source is complying with this NSPS. The permit should include:

 Whether the permittee is complying with the primary NSPS emission standard (1,100 lb CO 2 /MWh on a 12-operating-month rolling average) or the alternative compliance option (between 950 and 1,050 lb CO 2 /MWh on a 60-operating-month rolling average).

 The BACT emission limit that applies to the EGU (or EGUs) at the facility and that does not exceed the selected primary or alternative compliance option.

 Procedures for how the EGU will demonstrate compliance with the emission limit, based on the monitoring and recordkeeping requirements defined in §60.5355.

 A requirement that CO 2 produced by the EGU (or EGUs) is reported under Subpart PP by the owner or operator of the

EGU.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 267 of 403

 A requirement that all CO 2 that is geologically sequestered at the site of the EGU facility is reported under subpart RR by the owner or operator of the EGU.

 A requirement that the captured CO 2 sent offsite is transferred to an entity that is subject to the requirements of Subpart RR. We specifically request comment on this basic framework for PSD permits that are issued for affected EGU sources that use geologic sequestration.

**VIII. Rationale for Emission Standards for Natural Gas-fired Stationary Combustion Turbines**  A. Best system of emission reduction The EPA evaluated several different control technology configurations as potentially representing the “best system of emissions reductions ... adequately demonstrated” (BSER) for new natural gas-fired stationary combustion turbines: the use of full or partial capture CCS and several types of efficient generation without any CCS including high efficiency simple cycle aeroderivative turbines and natural gas combined cycle (NGCC) technology. We do not consider full or partial capture

CCS to be BSER because of uncertainties about technical feasibility and because of adverse impact on electricity prices and the structure of the electric power sector. In addition, we Comment [A115]: Is this technical feasibility or general feasibility (because of cost)***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 268 of 403 do not consider simple cycle turbines to be BSER because they have a higher emission rate and a higher cost than NGCC technology. We do find NGCC technology to be the BSER because it is technically feasible and relatively inexpensive, its emission profile is acceptably low, and it would not adversely affect the structure of the electric power sector. We note at the outset that currently, virtually all new sources in this category are using natural gas combined cycle (NGCC) technology. That technology is considered to be the state of the art for this source category. Because, in this rulemaking, we are considering, and selecting, NGCC as the BSER for this category, as a matter of terminology, to avoidconfusion, we generally refer to the sources as natural gasfired combustion turbines, and not as NGCC sources. 1. Full and partial CCS To determine the BSER for natural-gas-fired stationary source combustion turbines, we evaluated full and partial CCS against the criteria. We propose to reject CCS technology as the BSER because we cannot conclude that it meets several of the key

criteria. First, we are uncertain as to whether full or partial capture CCS is technically feasible for this source category. Unlike subpart Da affected facilities, where there are several***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 269 of 403 full-scale plants with CCS that are currently under construction or in advanced stages of development, the EPA is aware of only one demonstration project, which is an approximately 40 MW slip stream installation on a 320 MW NGCC unit. Importantly, there are some significant differences between natural gas-fired

combustion turbines and solid fossil fuel-fired EGUs that lead us to this conclusion. First, while some of these turbines are used to serve baseload power demand, many cycle their operation much more frequently than coal-fired power plants. It is unclear how part-load operation and frequent startup and shutdown events would impact the efficiency and reliability of CCS. We are not aware that any of the pilot-scale projects operate in that type of mode. None of the larger projects being constructed, or under development, are designed to operate in a cycling mode. Furthermore, the CO 2 concentration in the flue gas of a NGCC is much lower (usually approximately 4 volume percent) than the CO 2 concentration in the flue gas stream of a typical coal-fired plant (which is approximately 16 volume percent for a SCPC or CFB unit) or the syngas of an IGCC unit (where it can be as high as 60 volume percent )

. ), so the overall amount that can be captured for each project is likely lower. Moreover, identifying partial or full CCS as the BSER for new stationary combustion turbines would have significant Comment [A116]: The fact that there is a facility in demo phase seems to indicate that it IS technically feasible. However, it may not be economical or otherwise necessary in the regulatory context to pursue such an approach. In any case, this sentence does not support the topic sentence of this paragraph.

Comment [A117]: You mean the one demo project, the 40 MW slip stream? Rephrase to note one project, if so . If there are indeed multiple pilot projects, then this would support that it is technically feasible.

Comment [A118]: Need a conclusion here.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 270 of 403 adverse effects on national electricity prices, electricity supply, and the structure of the power sector. Because virtually all new fossil fuel-fired power is projected to use NGCC technology, requiring CCS would add significant costs to electricity generation across the nation. In addition, requiring CCS could lead some operators and developers to forego retiring older coal-fired plants and replacing them with new NGCC projects, and instead keep the older plants on line longer. Identifying CCS and BSER for combustion turbines would likely result in higher nationwide electricity prices and could adversely affect the supply of electricity, since virtually all new fossil fuel-fired power is projected to use NGCC technology. We recognize that identifying full or partial CCS would as the BSER for this source category would result in significant emissions reductions, but at present, we already considernatural gas to be a low-GHG-emitting fuel and NGCC to be a lowemitting technology. Although identifying CCS as the BSER would promote the development and implementation of emission control technology, for the reasons described, the EPA does not believe that CCS represents BSER for natural gas combustion turbines at

this time. 2. Energy efficient generation technology Comment [A119]: Cites? Referencces?

Comment [A120]: And this would have environmental impacts, also.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 271 of 403 To determine the BSER, the EPA also evaluated the use of energy efficient generation technology, including high efficiency simple cycle aeroderivative turbines. The use of high efficiency simple cycle aeroderivative turbines does not provide emission reductions from the current state-of-the-art technology – and, in fact, is more expensive than the current state-of-the-art technology – nor does it develop emission control technology. For these reasons, we do not consider it BSER. According to the AEO 2013 emissions rate information, this type of source has a CO 2 emissions rate of 1,150 lb CO 2 /MWh, which is higher than the emission rates of 830

and 760 lb CO 2 /MWh for the conventional and advanced NGCC model facilities, respectively. In the April 2012 proposal, we identified NGCC as the BSER for this source category, and proposed a standard of 1,000

lb/MWh. We stated: [A] NGCC facility is the best system of emission reduction for new baseload and intermediate load EGUs. To establish an appropriate, natural gas-based standard, we reviewed the emissions rate of natural gas-fired (non-CHP) combined cycle facilities used in the power sector that commenced operation between 2006 and 2010 and that report complete generation data to EPA. Based on this analysis, nearly 95% of these facilities meet the proposed standards on an annual basis. These units represent a wide range of geographic locations (with different elevations and***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 272 of 403 ambient temperatures), operational characteristics, and sizes. 212

The same information supports our current proposal. As described above, NGCC has a lower cost of electricity than simple cycle turbines at intermediate and high capacity factors. In addition, NGCC has an emissions rate that is approximately 25 percent lower than the most efficient simple cycle facilities. Therefore, the use of a heat recovery steam generator in combination with a steam turbine to generate additional electricity is a cost effective control for intermediate and high capacity factor stationary combustion turbines. Therefore, BSER for intermediate and high capacity factor stationary combustion turbines is the use of modern high efficiency NGCC technology. B. Determination of the standards of performance Multiple commenters on the April 2012 proposal stated the proposed standard of 1,000 lb CO 2 /MWh for combined cycle facilities in the April 2012 proposal was too stringent and should be increased to a minimum of 1,100 lb CO 2 /MWh. Commenters explained that the increased use of renewable energy for electricity generation will require combined cycle facilities to startup, shutdown, cycle, and operate at part-load more

212 77 Fed. Reg. at 22,414/1. Comment [A121]: This section would benefit from more explanation for why smaller NGCC units meet a particular need. Is it geographic specific? Is there a possibility that multiple new smaller units would be built instead of one larger unit?***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 273 of 403 frequently than they currently do, and that this more cyclical operation necessarily entails a higher emission rate. The

commenters stated that the recent historical emissions data that the EPA relied on for the original proposal does not account for these likely operational changes. Additional reasons given justifying a higher standard include the deterioration of efficiencies over time, the need for flexibility to use distillate oil as a backup fuel, the operation of combined cycle facilities in simple cycle mode, that combined cycle facilities located at high elevations and/or in locations with high ambient temperatures are less efficient, and that smaller combined cycle facilities are inherently less efficient than larger facilities. On the other hand, other commenters stated that the final standard should be lower than proposed on grounds that the best performing facilities are operating below the original proposed standard. Multiple commenters also stated that the EPA should evaluate additional CEMS data to determine the appropriate

standard. In light of these comments, we have reviewed the CO 2 emissions data from 2007 to 2011 for natural gas-fired (non-CHP) combined cycle units that commenced operation on or after January 1, 2000 and that reported complete electric generation data, including output from the steam turbine, to the EPA. A***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 274 of 403 more detailed description of this emissions data analysis is included in a technical support document in the docket for this rulemaking. These 307 NGCC units are diverse in location, age, capacity, and operating profile. Based on these data, we propose to subcategorize the turbines into the same two size-related subcategories currently in subpart KKKK for standards of performance for the combustion turbine criteria pollutants. These subcategories are based whether the design heat input rate to the turbine engine is either less than or equal to 850 MMBtu/h or greater than 850 MMBtu/h. We further propose to establish different standards of performance for these two subcategories. This subcategorization has a basis in differences in several types of equipment used in the differently sized units, which affect the efficiency of the units. Large-size combustion turbines use industrial frame type combustion turbines and may use multiple pressure or steam reheat turbines in the heat recovery steam generator (HRSG) portion of a combined cycle facility. Multiple pressure HRSGs employ two or three steam drums that produce steam at multiple pressures. The availability of multiple pressure steam allows the use of a more efficient multiple pressure steam turbine, compared to a single pressure steam turbine. A steam reheat turbine is used to improve the***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 275 of 403 overall efficiency of the generation of electricity. In a steam reheat turbine, steam is withdrawn after the high pressure

section of the turbine and returned to the boiler for additional heating. The superheated steam is then returned to the intermediate section of the turbine, where it is further expanded to create electricity. Although HRSGs with steam reheat turbines are more expensive and complex than HRSGs without them, steam reheat turbines offer significant reductions in CO 2 emission rates. In contrast, small-size combustion turbines frequently use aeroderivative turbine engines instead of industrial frame design turbines. While there is not a strict definition for an aeroderivative turbine, at least parts of aeroderivative turbines are derived from aircraft engines.

Aeroderivative and frame turbines use different combustor designs, lubrication oil systems, and bearing designs. While aeroderivative turbines are typically more expensive than industrial frame turbines, they are generally more compact, lighter, are able to start up and shut down more quickly, and handle rapid load changes more easily than compared to industrial frame turbines. Due to their higher simple cycle efficiencies, they have traditionally been used more for peak and intermittent purposes rather than base power generation. However, combined cycle facilities based on aeroderivative***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 276 of 403 combustion turbines are available. Due to the higher efficiency of the simple cycle portion of an aeroderivative turbine based combined cycle, the HRSG portion would contribute relatively less to the overall efficiency than a HRSG in a frame turbine based combined cycle. Therefore, adding a multiple steam pressure and/or a reheat steam turbine to the HRSG would be relatively more expensive to an aeroderivative turbine based combined cycle compared to a frame based combined cycle. Consequently, multiple pressure steam and reheat steam turbine HRSG are not widely available for aeroderivative turbine based combined cycle facilities. In addition, since aeroderivative turbine engines have faster start times and change load more quickly than frame turbines, aeroderivative turbine based combined cycles are more likely to run at part load conditions and to potentially bypass the HRSG and run in simple cycle mode for short periods of time than industrial frame turbine based combined cycle facilities. Because of these differences in equipment and inherent efficiencies of scale, the smaller capacity NGCC units (850 MMBtu/h and smaller) available on the market today are less efficient than the larger units (larger than 850 MMBtu/h). According to the data in the EPA’s Clean Air Markets Division database, there is a 7 percent difference in average CO 2 emission***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 277 of 403 rate between the small- and large-size units. This relative difference is consistent with what would be predicted when comparing the efficiency values reported in Gas Turbine World of small and large combined cycle designs. Fourteen of the study NGCC facilities evaluated using the Clean Air Markets data have heat input rates of less than or equal to 850 MMBtu/h, and the remaining 293 are above 850 MMBtu/MWh. Two of the small combined cycle facilities had a maximum 12-operating-month rolling average emissions rate equal to or greater than 1,000 lb CO 2 /MWh and one had an maximum 12-operating-month rolling average emissions rate equal to or greater than 1,000 lb CO 2 /MWh. Twenty three of the large turbines had at least one occurrence of a 12- operating-month rolling average emissions rate greater than or equal to 1,000 lb CO 2 /MWh and forty four had at least one occurrence of a 12-operating-month rolling average emissions rate greater than or equal to 950 lb CO 2 /MWh. Therefore, since the emission rates of 1,100 lb CO 2 /MWh and 1,000 lb CO 2 /MWh represent emission rates where over 90 percent of small and large existing NGCC are currently operating below respectively, these rates are considered BSER for new NGCC in those respective subcategories. These values represent the emission rates that a modern high efficiency NGCC located in the U.S. would be able to maintain over the life of the facility. Comment [A122]: Add citation.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 278 of 403 To further evaluate the impact of the proposed rule we reviewed the GHG BACT permits for 8 recently permitted NGCC facilities. Of these facilities, 7 are larger than 850 MMBtu/h, and 1 is smaller. The 7 larger ones all have emission rates below 1,000 lb/MWh, and as low as 880 lb/MWh. The single smaller unit, which is 400 MMBtu/h, has a permitted emissions rate of 1,100 lb CO 2 /MWh. We are requesting comment on a range of 950 to 1,100 lb

CO 2 /MWh (430 to 500 kg CO 2 /MWh) for the large turbine subcategory and 1,000 to 1,150 lb CO 2 /MWh (450 to 520 kg CO 2 /MWh) for the small turbine subcategory. **IX. Rationale for Other Requirements** A. Compliance Requirements The proposed compliance requirements, to the extent possible, incorporate monitoring already being performed as part of existing part 60 and part 75 requirements. We propose to recognize the environmental benefit of electricity generated by combined heat and power (CHP) facilities to account for the increased end use efficiency resulting from avoided transmission and distribution losses. To do so, we propose to allow CHP facilities, in calculating their

emission rate in lb CO 2 /MWh, deem their MWh to be 5 percent higher than actual their MWh, which would lead to a lower***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 279 of 403

emission rate. Actual transmission and distribution losses vary from location to location, but we propose that this 5 percent of actual MWh represents a reasonable average amount for the

avoided transmission and distribution losses for CHP facilities. Note that we propose to limit this 5 percent adjustment to facilities for which the useful thermal output is at least 20 percent of the total output. **X. Implications for PSD and Title V Programs**

A. Overview The proposal in this rulemaking would, for the first time, regulate GHGs under CAA section 111. Under the EPA’s regulations for the CAA PSD preconstruction permit program, and the CAA Title V operating permit program, regulation of GHGs under CAA section 111 triggers the applicability of PSD. Even so, today’s proposal should not require any additional SIP revisions to make clear that the Tailoring Rule thresholds – described below - continue to apply to the PSD program. This issue arises because States with approved PSD programs in their state implementation plans (SIPs) implement PSD, and most of these States have recently revised their SIPs to incorporate the higher thresholds for PSD applicability to GHGs that the EPA promulgated under what we call the Tailoring***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 280 of 403

Rule. 213 Commenters have queried whether under the EPA’s PSD regulations, promulgation of a section 111 standard of performance for GHGs would require these states to revise their SIPs again to incorporate the Tailoring Rule thresholds again. The EPA included an interpretation in the Tailoring Rule preamble, which makes clear that the Tailoring Rule thresholds continue to apply if and when the EPA promulgates requirements under CAA section 111. Even so, in today’s proposal, the EPA is including a provision in the CAA section 111 regulations that confirms this interpretation. However, if a state with an approved PSD SIP program that applies to GHGs believes that were the EPA to finalize the rulemaking proposed today, the state would be required to revise its SIP to make clear that the Tailoring Rule thresholds continue to apply, then (i) the EPA encourages the state to do so as soon as possible, and (ii) if the State cannot do so promptly, the EPA will assess whether to proceed with a separate rulemaking action to narrow its approval of that state’s SIP so as to assure that for federal purposes, the Tailoring Rule

213 “Prevention of Significant Deterioration and Title V Greenhouse Gas Tailoring Rule; Final Rule,” 75 FR 31514 (June 3, 2010). In the Tailoring Rule, EPA established a process for phasing in PSD and Title V applicability to sources based on the amount of their GHG emissions, instead of immediately applying PSD and title V at the 100 or 250 ton per year or thresholds included under the PSD and title V applicability provisions.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 281 of 403 thresholds will continue to apply as of the effective date of the final rule that the EPA is proposing today. In the alternative, if the Tailoring Rule thresholds did not continue to apply when the EPA promulgates requirements under CAA section 111, then the EPA would assess whether to proceed with a separate rulemaking action to narrow its approval of all of the State’s approved SIP PSD programs to assure that for federal purposes, the Tailoring Rule thresholds will continue to apply as of the effective date the final rule that EPA is proposing today. As discussed below, in the case of title V, today’s rulemaking does not have implications for the Tailoring Rule thresholds established with respect to sources subject to title V requirements. B. Implications for PSD program Under the PSD program in part C of title I of the CAA, in

areas that are classified as attainment or unclassifiable for NAAQS pollutants, a new or modified source that emits any air pollutant subject to regulation at or above specified thresholds is required to obtain a preconstruction permit. This permit assures that the source meets specified requirements, including application of best available control technology. States authorized for the PSD program may issue PSD permits. If a state Comment [A123]: Consider moving this text out of the Overview section and into the Implications Section. It is more informative to provide this after the background information.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 282 of 403 is not authorized, then the EPA issues the PSD permits. Regulation of GHG emissions in the Light Duty Vehicle Rule (75 FR 25324) triggered applicability of stationary sources to regulations for GHGs under the PSD and title V provisions of the CAA. Hence, on June 3, 2010 (75 FR 31514), the EPA issued the “Tailoring Rule,” which establishes thresholds for GHG emissions

in order to define and limit when new and modified industrial facilities must have permits under the PSD and title V programs.

The rule addresses emissions of six GHGs: CO 2 , CH 4 , N 2 O, HFCs,

PFCs and SF 6 . On January 2, 2011, large industrial sources, including power plants, became subject to permitting requirements for their GHG emissions if they were already required to obtain PSD or title V permits due to emissions of other (non-GHG) air pollutants. Commenters have queried whether, because of the way that the EPA’s PSD regulations are written, promulgating the rule we propose today may raise questions as to whether the EPA must revise its PSD regulations –- and, by the same token, whether states must revise their SIPs –- to assure that the Tailoring Rule thresholds will continue to apply to sources subject to PSD. That is, under the EPA’s regulations, PSD applies to a “major stationary source” that undertakes construction and to a “major modification.” 40 CFR 51.166(a)(7)(i) and (iii). A “major***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 283 of 403 modification” is defined as “any physical change in or change in the method of operation of a major stationary source that would result in a significant emissions increase . . . and a significant net emissions increase . . . .” Thus, for present purposes, the key component of these applicability provisions is that PSD applies to a “major stationary source.” The EPA’s regulations define the term “major stationary source” as a “stationary source of air pollutants which emits, or has the potential to emit, 100 [or, depending on the source category, 250] tons per year or more of any regulated NSR pollutant.” 40 CFR 51.166(b)(1)(i)( a ). The EPA’s regulations go on to define “regulated NSR pollutant” as follows, in relevant

part:

(b)(49) Regulated NSR pollutant, for purposes of this section, means the following: (i) Any pollutant for which a national ambient air quality standard has been promulgated and any pollutant identified under this paragraph (b)(49)(i) as a constituent or precursor to such pollutant.... (ii) Any pollutant that is subject to any standard promulgated under section 111 of the Act; (iii) Any Class I or II substance subject to a standard promulgated under or established by title VI of the Act;***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 284 of 403 (iv) Any pollutant that otherwise is subject to regulation under the Act as defined in paragraph (b)(48) of this section....

40 CFR 51.166(b)(49). Thus, the PSD regulations contain a separate PSD trigger for pollutants regulated under the NSPS, 40 CFR 51.166(b)(49)(ii) (the “NSPS trigger provision”), so that as soon as the EPA promulgates the first NSPS for a particular air pollutant, as we are doing in this rulemaking with respect to the GHG air pollutant, then PSD is triggered for that air pollutant. The Tailoring Rule, on the face of its regulatory provisions, incorporated the revised thresholds it promulgated into only the fourth prong (“[a]ny pollutant that otherwise is subject to regulation under the Act”), and not the second prong (“[a]ny pollutant that is subject to any standard promulgated under section 111 of the Act”). For this reason, a question may arise as to whether the Tailoring Rule thresholds apply to the PSD requirement as triggered by the NSPS that the EPA is promulgating in this rulemaking. However, although the Tailoring Rule thresholds on their face apply to only the term, “subject to regulation” in the definition of “regulated NSR pollutant,” the EPA stated in the Tailoring Rule preamble that the thresholds should be interpreted to apply to other terms in the definition of “major***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 285 of 403 stationary source” and in the statutory provision, “major emitting facility.” Specifically, the EPA stated:

3. Other Mechanisms As just described, we selected the “subject to regulation” mechanism because it most readily accommodated the needs of States to expeditiously revise – through interpretation or otherwise -- their state rules. Even so, it is important to recognize that this mechanism has the same substantive effect as the mechanism we considered in the proposed rule, which was revising numerical thresholds in the definitions of major stationary source and major modification. Most importantly, although we are codifying the “subject to regulation” mechanism, that approach is driven by the needs of the states, and our action in this rulemaking should be interpreted to rely on any of several legal mechanisms to accomplish this result. Thus, our action in this rule should be understood as revising the meaning of several terms in these definitions, including: (1) the numerical thresholds, as we proposed; (2) the term, “any source,” which some commenters identified as the most relevant term for purposes of our proposal; (3) the term, “any air pollutant; or (4) the term, “subject to regulation.” The specific choice of which of these constitutes the nominal mechanism does not have a substantive legal effect because each mechanism involves one or another of the components of the terms “major stationary source” - which embodies the statutory term, “major emitting facility” -- and “major modification,” which embodies the statutory term, “modification,” and it is those statutory and regulatory terms that we are defining to exclude the indicated GHG-emitting sources. [Footnote] [Footnote: We also think that this approach better clarifies our long standing practice of interpreting open-ended SIP regulations to automatically adjust for changes in the regulatory status of an air pollutant, because it appropriately assures that the Tailoring Rule applies to both the definition of “major stationary source” and “regulated NSR pollutant.” ]***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 286 of 403

75 FR 31582. Thus, according to the preamble of the final Tailoring

Rule , the definition of “major stationary source” itself already incorporates the Tailoring Rule thresholds, and not just through one component (the “subject to regulation” prong of the term “regulated NSR pollutant”) of that definition. For this reason, it is the EPA’s position that the Tailoring Rule thresholds continue to apply even when the EPA promulgates the first NSPS for GHGs (which, as noted above, triggers the PSD requirement under the NSPS trigger provision in the definition of “regulated NSR pollutant”). 214 To clarify and confirm that the Tailoring Rule thresholds apply to the section 111 prong of the definition of regulated NSR pollutant, in this proposed rulemaking, the EPA is proposing to revise the NSPS regulations, although not the PSD regulations, to explicitly make clear that the NSPS trigger

214 This position reads the regulations to be consistent with the CAA PSD provisions themselves. Under those provisions, PSD applies to any “major emitting facility,” which is defined to mean stationary sources that emit or have the potential to emit “any air pollutant” at either 100 or 250 tons per year, depending on the source category. CAA section 165(a), 169(1). EPA has long interpreted these provisions to apply PSD to a stationary source that emits the threshold amounts of any air pollutant subject to regulation. See Tailoring Rule, 75 FR 31579. Under these provisions, at present, PSD is already applicable to GHGs because GHGs are already subject to regulation, and regulating GHGs under CAA section 111 does not any additional type of PSD trigger. Comment [A124]: The last clause of this FN seems to be missing a word.

Formatted: Highlight***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 287 of 403 provision in the PSD regulations incorporate the Tailoring Rule thresholds. The rationale for the Tailoring Rule thresholds remains equally applicable in this context. As a result, the EPA believes that states that incorporated the Tailoring Rule thresholds into their SIPs may take the position that they also incorporated the EPA’s interpretation in the preamble that the thresholds apply to the definition “major stationary source.” The EPA requests that all States with approved SIP PSD programs that apply to GHGs indicate during the comment period on this rule whether they can interpret their SIPs already to apply the Tailoring Rule thresholds to the NSPS prong or whether they must revise their SIPs. For any State that says it must revise its SIP (or that does not respond), the EPA will assess whether to propose a rule that is comparable to the SIP PSD Narrowing Rule shortly after the close of the comment period, and may finalize that rule at the same time that it finalizes

this NSPS rule. C. Implications for title V program Under the title V program, a source that emits any air pollutant subject to regulation at or above specified thresholds (along with certain other sources) is required to obtain an operating permit. This permit includes all of the CAA***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 288 of 403 requirements applicable to the source. These permits are generally issued through EPA-approved State title V programs. As the EPA explained in the Tailoring Rule preamble, title V applies to a “major source,” CAA section 502(a), which is defined to include, among other things, certain sources, including any “major stationary source,” CAA section 501(2)(B), which, in turn, is defined to include a stationary source of “any air pollutant” at or above 100 tpy. CAA section 302(j). The EPA’s regulations under title V define the term “major source,” and in the Tailoring Rule, the EPA revised that definition to make clear that the term is limited to stationary sources that emit any air pollutant “subject to regulation.” The EPA incorporated the Tailoring Rule threshold within the definition of “subject to regulation.” The EPA described its action as follows in the preamble to the Tailoring Rule: Thus, EPA is adding the phrase “subject to regulation” to the definition of “major source” under 40 CFR 70.2 and 71.2. EPA is also adding to these regulations a definition of “subject to regulation.” Under the part 70 and part 71 regulatory changes adopted, the term “subject to regulation,” for purposes of the definition of “major source,” has two components. The first component codifies the general approach EPA recently articulated in the “Reconsideration of Interpretation of Regulations That Determine Pollutants Covered by Clean Air Act Permitting.” 75 FR 17704. Under this first component, a pollutant “subject to regulation” is defined to mean a pollutant subject to either a provision in the CAA or regulation adopted by EPA under the CAA that requires actual control of emissions of that pollutant***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 289 of 403

and that has taken effect under the CAA. See id . at 17022-23; Wegman Memorandum at 4-5. To address tailoring for GHGs, EPA includes a second component of the definition of “subject to regulation,” specifying that GHGs are not subject to regulation for purposes of defining a major source, unless as of July 1, 2011, the emissions of GHGs are from a source emitting or having the potential to emit 100,000 tpy of GHGs on a CO 2 e basis. 75 Fed. Reg. at 31,583. Unlike the PSD regulations described above, the title V definition of “major source”, as revised by the Tailoring Rule, does not on its face distinguish among types of regulatory triggers for title V. Because title V has already been triggered for GHG-emitting sources, the promulgation of CAA section 111 requirements has no further impact on title V applicability requirements for major sources of GHGs. Accordingly, today’s rulemaking has no title V implications with respect to the Tailoring Rule threshold. Of course, unless exempted by the Administrator through regulation under CAA section 502(a), sources subject to a NSPS are required to apply for, and operate pursuant to, a title V permit that assures compliance with allapplicable CAA requirements for the source, including any GHGrelated requirements. We have concluded that this rule will not affect non-major sources and there is no need to consider whether to exempt non-major sources. Note that we propose to move the definition of “Greenhouse***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 290 of 403 gases” currently within the definitions of “Subject to regulation” in 40 CFR 70.2 and 71.2 to a definition within 70.2 and 71.2 to promote clarity in the regulations. D. Implications for title V fees requirements for GHGs The issuance of the final EGU GHG NSPS will trigger certain requirements related to title V fees for GHG emissions under 40 CFR part 70 and part 71. States (including approved local and tribal permitting authorities) will be required to include GHG emissions in determining whether they collect adequate fees, if the state relies on the “presumptive minimum” approach to demonstrating fee adequacy. In addition, sources subject to federal permitting under part 71 will be required to include GHG emissions in calculating their annual permit fee. 215 The EPA is proposing changes to the title V rules to limit the impact of the requirements that would otherwise occur under the existing rules, provide flexibility to the states to ensure sufficient funding for their programs, and to ensure that the requirements

are consistent with the Clean Air Act. These requirements would be triggered because the regulation of GHGs under section 111 for the first time through

215 Also, we understand several states may have fee requirements that are structured with similar definitions that would result in GHGs being added to the list of air pollutants that are subject to title V fees.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 291 of 403 the issuance of the EGU GHG NSPS would make GHGs a “regulated air pollutant,” as defined under 40 CFR parts 70 and 71, a “regulated pollutant (for presumptive fee calculation)” as defined under part 70 and a “regulated pollutant (for fee calculation)” as defined under part 71. Under the current part 70, regulation of GHGs under section 111 through the issuance of any NSPS would result in GHGs being added to the list of air pollutants used in “presumptive minimum” fee calculations. Also, in EPA’s part 71 permit program, and possibly in certain state part 70 programs, issuance of a NSPS standard would result in GHGs being added to the list of air pollutants that are subject to fee payment by sources. This effect of adding GHGs to certain title V fee requirements was not discussed in the previous proposal for the EGU GHG NSPS; however, several public comments were raised on this issue, and a number of related issues, during the public comment period on the previous proposal for the EGU GHG NSPS. In this re-proposal of the EGU GHG NSPS, we discuss this issue for GHGs related to title V fees and propose rule amendments that will enable permitting authorities to collect fees as needed to support their programs, to avoid excessive and unnecessary fees. We also respond to and clarify some related issues raised by commenters on the previous proposal.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 292 of 403 In summary, we are proposing to exempt GHGs from the presumptive fee calculation, yet account for the costs of GHG permitting program costs through a cost adjustment to ensure

that fees will be collected that are sufficient to cover the program costs. We are also proposing that permitting agencies that do not use the presumptive fee approach can continue to demonstrate that their fee structures are adequate to implement their title V programs. Prior to explaining our proposal in more detail, the following discussion provides background on the fee requirements of the title V rules, what those fees cover in terms of agencies’ program implementation, what additional activities agencies might be expected to have to undertake as a result of GHGs becoming “regulated pollutants” under the NSPS, what the GHG Tailoring Rule said about title V fees, background on title V fees in the context of the previous proposal for the EGU GHG NSPS, and existing limitations on the collection of GHG fees. 1. Background

a. The title V rules Title V is implemented through 40 CFR parts 70 and 71. Part 70 defines the minimum requirements for state, local and tribal (state) agencies to develop, implement and enforce a title V operating permit program; these programs are developed***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 293 of 403 by the state and the state submits a program to EPA for a review of consistency with part 70. There are about 112 approved part 70 programs in effect, with about 15,000 part 70 permits currently in effect. (See Appendix A of 40 CFR part 70 for the approval status of each state program). Part 71 is a federal permit program run by the EPA, primarily where there is no part 70 program in effect (e.g., in Indian country, the federal OCS and for offshore LNG terminals). 216 There are about 100 part 71 permits currently in effect (most are in Indian country).

b. The fee requirements of title V Section 502(b)(3)(A) of the Act requires owners or operators of all sources subject to permitting to “pay an annual fee, or the equivalent over some other period, sufficient to cover all reasonable (direct and indirect) costs required to develop and administer the permit program.” Section 502(b)(3)(B) of the Act generally sets forth the methods for determining whether a permitting authority is collecting sufficient fees in total to cover the costs of the program. First, under the “presumptive minimum” approach set forth in section

216 In some circumstances, EPA may delegate authority for part 71 permitting to another permitting agency, such as a tribal agency or a state. The EPA has entered into delegation agreements for certain part 71 permitting activities with at least one tribal agency. There are currently no states that do not have an approved part 70 program; thus, there is no need for EPA to delegate part 71 permitting authority to any state at this time. Comment [A125]: Spell out***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 294 of 403 502(b)(3)(B)(i), a state can satisfy the requirement by showing that “the program will result in the collection, in the aggregate, from all sources subject to [the program] of an amount not less than $25 per ton of each regulated pollutant, or such other amount as the Administrator may determine adequately reflects the reasonable costs of the permit program.” The statute further provides that emissions in excess of 4,000 tpy for any one pollutant need not be included in the calculation, and that the initial fee rate ($25 per ton) shall be adjusted

for inflation 217 . See section 502(b)(3)(B)(iii)-(v). Also, section 502(b)(3)(B)(ii) of the Act sets forth a definition of “regulated pollutant” for purposes of the presumptive fee calculation that includes, in part, each pollutant regulated under section 111 of the Act, such as any pollutants regulated under any NSPS, which would make GHG a “regulated pollutant” based on our proposal for the EGU GHG NSPS. Each of the title V rules that implement title V contains a definition of “regulated air pollutant” 218 (at 40 CFR 70.2 and 71.2) that tracks the Act

217 The current corresponding part 70 fee rate, adjusted for inflation, is approximately $47 per ton. 218 The definition reads in relevant part : “Regulated air pollutant means the following: (1) Nitrogen oxides or any volatile organic compounds; (2) Any pollutant for which a national ambient air quality standard has been promulgated; (3) Any pollutant that is subject to any standard promulgated under section 111 of the Act; (4) Any Class I or II substance subject***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 295 of 403 definition of “regulated pollutant.” The “regulated air pollutant" definition is used in the regulatory text for applicable requirements and other purposes and it is relevant for fee purposes because it is cross-referenced as the starting point for two fee-related definitions: “regulated pollutant (for presumptive fee calculation) 219 ” in 40 CFR 70.2 and “regulated pollutant (for fee calculation) 220 ” in 40 CFR 71.2. Alternatively, if a state does not wish to show it collects an amount of fees at least equal to the presumptive minimum amount, section 502(b)(3)(B)(iv) provides that a program may be approved if the state demonstrates that it collects sufficient fees to cover the costs of the program, even if that amount is below the presumptive minimum.

to a standard promulgated under or established by title VI of the Act; or (5) Any pollutant subject to a standard promulgated under section 112 or other requirements established under section 112 of the Act, including sections 112(g), (j), and (r) of the Act . . .” 219 40 CFR 70.2 defines r egulated pollutant (for presumptive fee calculation) to mean: “any ‘regulated air pollutant’ except the following: (1) Carbon monoxide; (2) Any pollutant that is a regulated air pollutant solely because it is a Class I or II substance to a standard promulgated under or established by title VI of the Act; or (3) Any pollutant that is a regulated air pollutant solely because it is subject to a standard or regulation under section 112(r) of the Act.” 220 40 CFR 71.2 defines r egulated pollutant (for fee calculation ) the same as r egulated pollutant (for presumptive fee calculation in 40 CFR 70.2.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 296 of 403 The presumptive fee approach of the statute is reflected in the part 70 regulations for those states that wish to use it for fee adequacy purposes. In addition, for the federal part 71 permitting program, which the EPA implements directly, the EPA has adopted rules to ensure that it collects adequate fees, consistent with the statute. These Act requirements for fees are reflected in 40 CFR 70.9 and 71.9, respectively. Although the Clean Air Act and part 70 require that a title V permit program must collect sufficient fees to cover the costs of the program, neither the Act nor part 70 specifies the details of how those fees must be charged to particular sources in their fee schedules. The part 70 regulations specifically provide, at 40 CFR 70.9(b)(3), that a “state program’s fee schedule may include emission fees, application fees, service fees or other types of fees, or any combination thereof.” Many states use emission fees and other types of fees in combination

in their fee schedules and we understand that some state fee schedules are structured such that they would result in GHG fees being required when GHGs are regulated under any NSPS. For example, states may have chosen for convenience sake to use the “regulated pollutant (for presumptive fee calculation)” definition of part 70, or a similar state definition, to identify the pollutants subject to fees as part of their fee***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 297 of 403schedule. For part 71, the EPA chose to promulgate an emissionsbased fee schedule that uses the definition of “regulated pollutants (for fee calculation)” to identify the pollutants subject to fees, and thus, part 71 is structured such that GHG fees would be required when GHGs are regulated under any NSPS. State fee schedules charge emissions-based fees that range from about $15 to $100 or more per ton for each air pollutant for which they charge a fee, while part 71 charges about $48 per

ton 221 , effective for calendar year 2013, for each of the “regulated pollutants (for fee calculation).” See 40 CFR 71.9(c)(1). Most part 70 and part 71 programs require sources to pay the fees on an annual basis, initially with the submittal of its permit application, and thereafter, on the anniversary of application submittal. See 40 CFR 70.9(a), 71.9(e). Section 502(b)(3)(A) of the CAA broadly requires permit fees “sufficient to cover all reasonable (direct and indirect) costs required to develop and administer the permit program” including the reasonable costs of: “(i) reviewing and acting upon any application for such a permit, (ii) implementing and

221 Note that the part 71 fee rate and the part 70 presumptive fee rate are slightly different because the part 71 rate was set based on an analysis that showed that the EPA needed slightly more than the presumptive minimum to collect sufficient revenue to fund the program.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 298 of 403 enforcing the terms and conditions of any such permit (not including any court costs or other costs associated with any enforcement action), (iii) emissions and ambient monitoring, (iv) preparing generally applicable regulations, or guidance, (v) modeling, analyses, and demonstrations, and (vi) preparing inventories and tracking emissions.” These statutory requirements were incorporated into the regulations at 40 CFR 70.9(b)(1) and 71.9(b), EPA has provided detailed guidance on EPA’s interpretation of this list of activities in several memoranda, 222 and these activities have been considered in the context of the ICR development and renewal process for part 70

and 71.

c. How EPA Addressed Title V Fees in the Tailoring Rule The GHG Tailoring Rule concerned when sources are required to obtain permits under prevention of significant deterioration (PSD) and title V due to emissions of GHGs. ( See Prevention of Significant Deterioration and Title V Greenhouse Tailoring Rule; Final Rule [the Tailoring Rule]; 75 FR 31514, June 3, 2010.) GHGs became subject to regulation as a result of the Light Duty Vehicle Rule (75 FR 25,234, May 7, 2010), and the Tailoring Rule

222 For example, see “Reissuance of Guidance on Agency Review of State Fee Schedules for Operating Permits Programs Under Title V”; from John S. Sietz, Director, Office of Air Quality Planning and standards, to Air Division Director s, Regions I-X; August 4, 1993; available at http://www.epa.gov/region07/ air/title5/t5memos/fees.pdf.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 299 of 403 established emissions thresholds for purposes of PSD and title V. Neither the Light Duty Vehicle Rule nor the Tailoring Rule made any changes that would cause GHGs to meet the definition of “regulated air pollutant,” or related fee definitions in the title V regulations. EPA has promulgated no other standards that would trigger fee requirements for GHGs in title V programs. The GHG Tailoring Rule addressed the possible need for states and the EPA to charge fees for GHG emissions based on the burdens imposed under the Tailoring Rule for states to incorporate GHGs into permits or to issue permits to sources based on GHG emissions. We did not revise the part 70 rules to require fees for GHGs, although we did clarify that states have the option of charging fees to recover the costs of permitting related to GHGs. Also, we did not revise part 71 to require GHG fees, and we stated that we would review the need for additional fees to cover program costs for GHGs over time. (See 75 FR 31526 and 31584.) We retained this approach in last year’s Step 3 Tailoring Rule. (See Prevention of Significant Deterioration and Title V Greenhouse Tailoring Rule Step 3, GHG Plantwide Applicability Limitations and GHG Synthetic Minor Limitations, (Step 3 of the Tailoring Rule), 77 FR 41051, July 12, 2012).

d. Title V fees in the previous EGU GHG NSPS proposal***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 300 of 403 The previous EGU GHG NSPS proposal did not discuss any title V fee issues related to regulating GHGs under a section 111 standard; however, several public commenters (two state agencies and one industry group) raised several concerns or

asked for clarification on a number of issues related to title V fees during the public comment period. Two of these commenters requested clarification as to whether the issuance of the EGU

GHG NSPS would make either GHGs or CO 2 subject to regulation such that title V fee requirements would be triggered for either of these pollutants. One commenter requested clarification on whether fees are required for “regulated NSR pollutants,” such as GHG. One commenter questioned whether the rationale of the Tailoring Rule for deferring fees for GHGs would also apply to the EGU GHG NSPS. Finally, one commenter asked us to clarify if a state could refrain from charging a fee for CO 2 (based on the issuance of the EGU GHG NSPS) if the state otherwise generates a fee sufficient to meet the “program support requirements” of

title V. Note that we address the substance of several of these comments related to title V fees in section B of this portion of the proposal.

e. Unique Characteristics of GHGs relative to Fees There are a number of provisions in part 70 and part 71 and characteristics of GHGs that are relevant to any discussion***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 301 of 403 related to charging fee for GHGs. First, it should be noted that GHG are emitted in extremely high quantities relative to other air pollutants, such as the criteria pollutants, which are typically emitted by combustion sources that also emit GHGs. A

review of emission factors in EPA’s AP-42 shows that GHGs are typically emitted in quantities as much as one thousand or more times higher than CO or NO X and many other pollutants as a product of combustion for a given mass of fuel 223 . Thus, we expect that charging fees for GHGs at the same rate (in dollars per ton) as other regulated air pollutants would lead to fee revenue that would be excessive, far beyond the reasonable costs of the program. Even though most part 70 and 71 programs cap total fees at 4,000 tons per air pollutant per year 224 we note that the total GHG fee for a particular source under the current part 71 rule could still be significant, up to about $194,000 per year for GHGs alone, if GHGs are charged at the same rate as for other “regulated pollutants (for fee calculation).” 225

223 See AP-42, Compilation of Air Pollution Emission Factors, Volume I, Stationary and Area Sources, Fifth Edition. For example, for external combustion of bituminous and subbituminous coals, see table 1.1-3 for NOx and CO emission factors and table 1.1-20 for CO 2 emissions factors. 224 Consistent with the option afforded states at 40 CFR 70.9(b)(2)(ii)(B) and the EPA’s fee schedule at 40 CFR 71.9(c)(5). 225 Note that most sources that emit GHGs, particularly major sources of GHG, also emit other regulated air pollutants subject***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 302 of 403 Second, unlike other pollutants, GHGs can be estimated in two ways: by mass or by CO 2 equivalent (CO 2 e). While the title V permitting threshold for the Tailoring Rule was established at 100,000 CO 2 e and 100 tpy mass, the fee provisions of part 70 and 71, and we believe the fee provisions of the majority, if not all, state programs, charge fees on a mass (per ton), rather

than on a CO 2 e 226 , basis. See 40 CFR 70.9(b)(2)(i) and 40 CFR 71.9(c)(1).

2. Response to comments on fees from the previous EGU GHG NSPS proposal In response to concerns raised by commenters, and because response to certain of these issues will help to provide a better proposal, we respond to several of these comments at this time. In response to the question as to whether CO 2 or GHGs would be regulated by the EGU GHG NSPS, we clarify that GHG would be regulated under section 111 of the Act and that this does not affect the applicability thresholds previously

to fees; thus, they would pay significant title V fees even if a fee for GHGs is not charged. 226 The term “tpy CO 2 equivalent emissions” (or “CO 2 e”) is defined within the definition of “subject to regulation” in 40 CFR 70.2 and 71.2. The definitions read, in relevant part, “[CO2e] shall represent an amount of GHGs emitted, and shall be computed by multiplying the mass amount of emissions (tpy), for each of the six greenhouse gases in the pollutant GHGs, by the gas's associated global warming potential published at Table A-1 to subpart A of part 98 of this chapter—Global Warming Potentials, and summing the resultant value for each to compute a tpy CO 2 e.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 303 of 403 established for PSD and title V in the Tailoring Rule. First, the EPA considers the pollutant being regulated by the NSPS for the purposes of PSD and by title V to be GHG, rather than CO 2 . Thus, under this interpretation, this NSPS has not caused CO 2 to be treated as a “regulated air pollutant” under the third prong of the definition of “regulated air pollutant” contained in 40 CFR 70.2 and 71.2, which includes “[a]ny pollutant that is subject to any standard promulgated under section 111 of the Act,” because it causes GHG to be the “regulated air pollutant.” Second, although EPA’s PSD regulations provide that regulation of GHGs under CAA section 111 triggers PSD applicability, the Tailoring Rule thresholds for GHG continue to apply for major source applicability for both the PSD and Title V permitting programs. We have clarified these points further in a memorandum we have added to the docket for this rulemaking (“PSD ThresholdMemorandum,” dated May 8, 2012). (See document number EPA-HQOAQPS-2011-0660-7602 )

. In response to the comment inquiring whether the rationale of the Tailoring Rule remains relevant for deferring action on fees, we are proposing several revisions to the part 70 and part 71 regulations in response to the proposed regulation of GHGs under section 111, while retaining the general approach that we described in the Tailoring Rule. At the time of the promulgation***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 304 of 403 of the Tailoring Rule, there were no section 111 standards (or other standards) that had been promulgated that would have resulted in title V fee requirements being triggered for GHGs. Thus the rationale we use now is necessarily different that the rationale we used for the Tailoring Rule fee discussion. If the commenter is referring to the requests of certain state agencies in their comments on the Tailoring Rule for the EPA to set a presumptive fee of GHGs, we are responding to that request in this proposal by proposing to set a presumptive fee cost adjustment. If the commenter is referring to the fee flexibility afforded by 40 CFR 70.9(b)(3), we respond that we are not proposing to revise that regulatory provision. A state commenter generally asked us if it could not refrain from requiring a fee

for CO 2 (or GHG) if it could show that they can otherwise generate a fee sufficient to meet the “program support requirements” of title V. The response to this comment is yes, based on the following analysis. Title V requires permitting

authorities to collect fees from sources that are ‘‘sufficient to cover all reasonable (direct and indirect) costs required to develop and administer [title V] programs.” 227 States have adopted various fee schedules to meet this requirement. 40 CFR

227 The fee provisions are set forth in CAA section 502(b)(3) and in our regulations at 40 CFR 70.9 and 71.9.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 305 of 403 70.9(b)(3) allows a State program's fee schedule to include emissions fees, application fees, service-based fees or other types of fees, or any combination thereof, to meet the requirements of the collection and retention of revenues sufficient to cover the permit program costs. Further, states are not required to calculate fees on any particular basis or in the same manner for all part 70 sources or for all regulated air pollutants, provided that they collect a total amount of fees sufficient to meet the program support requirements. This flexibility is also true for states that use the presumptive minimum approach to demonstrate they would collect sufficient fees to fund the program. In the final Tailoring Rule (75 Fed. Reg. 31584, June 3, 2010), we did not change our fee regulations to require title V fees for GHGs or require new fee demonstrations from states related to permitting GHGs, and we have retained the same policies for the purposes of the recent Step 3 rule (77 Fed. Reg. 41051, July 12, 2012). In the final Tailoring Rule, we recommended that each state, local or tribal program review its resource needs for GHGs and determine if the existing fee approaches would be adequate. If those approaches were not adequate, we suggested that they should be proactive in raising fees to cover the direct and indirect costs of the program or develop other alternative approaches to meet the***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 306 of 403 shortfall. Therefore, we agree with the commenter that consistent with 40 CFR 70.9(b)(3), if a state generates fees “sufficient to meet the program support requirements,” without charging fees based on GHG emissions, then a fee does not have to be charged specifically for GHGs. 228 Thus, this proposal does not seek to revise fee schedule flexibility for states and instead focuses on revising the presumptive minimum fee provisions under part 70 to more appropriately account for GHG program costs. This notice does not propose any new requirements for states that do not use the presumptive approach to establish adequacy of fees.

3. Today’s proposal to address GHGs in title V fees In this part of the preamble we explain and solicit comment on options to address the title V fee issues raised by the proposed regulation of GHGs under this NSPS. In sum, we propose to exempt GHGs from the presumptive fee calculation, yet account for the costs of GHG permitting through a cost adjustment to

ensure that fees will be collected that are sufficient to cover the program costs

. We request comment on these proposals, particularly from state, local, and tribal permitting agencies,

228 Conversely, where a state cannot show that sufficient fees are being collected, the state would need to modify its fee schedule (which could, but need not, involve charging fees for GHG emissions).***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 307 of 403 and particularly with respect to which approach would be most appropriate, feasible, and workable and result in fees that would be adequate to cover the direct and indirect costs of permitting GHGs. We also invite comments on ways to improve this proposal and/or address this issue in other ways consistent with the same principles, concerns, and statutory authority that we have described for this proposal.

a. Exemption of GHGs from presumptive fee calculation For the reasons discussed earlier in this proposal, we propose to exempt GHGs from the definition of “regulated pollutant (for presumptive fee calculation)” in 40 CFR 70.2 in order to exclude GHGs from being subject to the statutory fee rate set for the presumptive minimum fee calculation of 40 CFR 70.9(b)(2)(i). Pursuant to the authority of section 502(b)(3)(B)(i), we are proposing to determine that utilizing the statutory fee rate for GHGs would be inappropriate because it would result in excessive fees, far above the reasonable costs of a program. Thus, nd we are proposing a significantly smaller cost adjustment for GHGs to reflect the program costs

related to GHGs. We have estimated the cost of permitting GHGs associated with the Tailoring Rule thresholds in several documents, in an economic analysis performed for the Tailoring Rule and in***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 308 of 403 several documents related to Information Collection Request (ICR) requirements for part 70 and 71, and we believe these analyses provide a basis for estimating the costs related to GHG permitting for the typical permitting authority. Thus, we propose to revise 40 CFR 70.9(b)(2)(i) to add a GHG cost adjustment to account for the GHG permitting program costs.

b. Addition of a GHG cost adjustment to the presumptive minimum

fee calculation We propose to revise the presumptive minimum fee provisions of part 70 to add a GHG cost adjustment to account for the typical GHG permitting program costs that may not already be covered by the existing presumptive minimum fee provisions of parts 70 and 71. The current presumptive minimum fee provisions of the title V rules implements the statutory mandate to collect

fees that are sufficient to cover the direct and indirect GHG program costs. Since we are not proposing to charge fees for GHGs at the statutory rate ($25 per ton, adjusted for inflation) due to concerns raised by permitting authorities and others about this resulting in excessive fees, we may need an alternative presumptive minimum fee to recover any costs related to GHGs that would not otherwise be covered by the presumptive minimum fee that is calculated based on emissions of regulated air pollutants, excluding GHGs. We estimated certain incremental***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 309 of 403 GHG program costs that would not be covered under the context of the Tailoring Rule, but we did not revise our permit rule to

reflect those costs at that time. We are aware that the EGU NSPS may further increase permitting authority costs above the levels that would be covered by presumptive minimum fee provisions that exclude GHGs, and we are concerned that accounting for GHGs using the statutory rate would result in excessive calculation of costs. Thus, to address these concerns, we are soliciting comment on several proposed options to adjust the presumptive minimum fee provisions of the regulations, including an option that would calculate no additional costs for GHGs, a modest additional cost for each GHG-related activity of certain types that a permitting authority would process over the period covered by the presumptive minimum fee calculation, and a modest additional increase in the per ton rate used in the presumptive

minimum calculation. When we promulgate step 4 of the Tailoring Rule, and depending on EPA’s proposal(s) and final action(s) there, we may revisit the GHG cost adjustment and potentially revise it, taking into account any changes in permitting authority costs for GHGs related to the obligations for permitting authorities under that rulemaking.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 310 of 403 In addition, as a general matter, the presumptive minimum adjustments for part 70 we propose for GHGs are based, in part, on information concerning permitting authority burden (in hours) and cost (in dollars) contained in the Information Collection Request (ICR) renewal for part 70 229 approved by the Office of Management and Budget on October 3, 2012 for the 36 month period of October 31, 2012 through September 30, 2015. Also, this information is consistent with, and updates, burden and cost information in the Regulatory Impact Assessment (RIA) for the Tailoring Rule 230 and an ICR change request for the GHG Tailoring Rule (EPA ICR Number 1587.11), which was approved by OMB at the time of the promulgation of the Tailoring Rule 231 . These assumptions are relevant through step 3 of the implementation of the Tailoring Rule. The supporting statement for the ICR renewal for part 70 sets forth our estimate of the three-year and annual incremental burden related to certain activities performed by permitting authorities under the Tailoring Rule. (See Supporting Statement for the Part 70 state Operating Permits Program,

229 The most recent part 70 ICR renewal is identified as EPA ICR number 1587.12 and the ICR for part 70 has been assigned OMB control number 2060-0243. 230 Regulatory Impact Analysis for the Final Prevention of Significant Deterioration and Title V Greenhouse Gas Tailoring Rule, Final Report, May 2010. 231 The ICR change request form for the Tailoring Rule was based on the assumptions made in the RIA for the Tailoring Rule.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 311 of 403 document number EPA-HQ-OAR-2004-0016-0023). The information in the supporting statement is designed to be a directionally correct assessment of costs, and thus, may serve as a starting point for considerations of the possible range of costs to consider when proposing adjustments to the presumptive minimum fee provisions of part 70 to appropriately account for GHG permitting program costs.

We are proposing to adjust GHG costs by adding a cost for each GHG-related activity of certain types that a permitting authority may perform over the period covered by a presumptive minimum fee calculation. Additional information supporting this approach may be found in part in Table 12 of the supporting statement (in the ICR) summarizes the permitting authority burden for particular GHG-related permitting activities. Table 12 in the ICR shows certain incremental burden assumptions for certain activities related to GHG permitting program costs in the form of an hourly burden for each activity that a permitting authority may process. Based on observations regarding permitting activities since the Tailoring Rule, we have adapted these assumptions for the purposes of this option and included certain activities with a somewhat different description than we used in the table in the ICR in an attempt to more accurately***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 312 of 403 reflect the types of permitting activities that have occurred in the GHG permit program. In addition, by making these clarifying changes, we are trying to more closely track the language in the CAA and parts 70 and 71 regarding the specific of the permit process. We are proposing to include three general activities in this proposed option: 1) “completeness determination (for new permits or for updated applications)” at 43 hours, 2) “modification at the facility or a permit that requires a GHG evaluation” at 7 hours, and 3) “evaluate GHG at permit renewal”

at 10 burden hours. 232 The GHG cost adjustment for the presumptive fee would be calculated under this approach by multiplying the burden hours for each activity by the cost of staff time (in $ per hour), including wages, benefits, and

232 The first item, “completeness determination” is essentially the first step performed by the permitting authority once an application is submitted. See, e.g., 40 CFR 70.5(a)(2). The second item, “modification at the facility or a permit that requires a GHG evaluation” applies where a modification is occurring at the facility and the permitting authority is obligated to undertake an analysis of whether such modification triggered any GHG related requirements. This might occur, for example, where a synthetic or true minor application is submitted and the permitting authority needs to undertake a GHG related analysis. The third item, “evaluate GHG at permit renewal” applies where the permitting authority receives a renewal application that is not coupled with any facility modifications. EPA suggests this language because it is more closely tied to the specific work to be performed by permitting authorities consistent with statutory and regulatory obligations.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 313 of 403 overhead, as determined by the state for the particular

activities undertaken.

Note that some of these activities are one-time activities that may not extend beyond the expected end of step 3 of the Tailoring Rule.

We are also co-proposing an alternative option under which we would increase the fee rate used in the presumptive minimum calculation for each regulated air pollutant, excluding GHGs. This option would rely primarily on data concerning the state burdens of permitting GHGs through step 3 of the tailoring rule found in the Information Collection Request (ICR) for part 70. This suggests that when looking at Tailoring Rule burdens in isolation, that GHG permitting increases permitting authority burden by about 7 percent 233 , which would be multiplied by the presumptive minimum fee rate in effect to calculate the revise presumptive fee rate to account for GHG. Under this approach, the new presumptive minimum fee effective for the current period would be $50.00 per ton for each regulated pollutant (for

233 Table 14 shows 102,122 hours for GHG tailoring rule divided by 1,414,293 hours baseline permitting authority cost (unadjusted) and Table 15 shows $5.5 million for GHG tailoring rule divided by $76.4 million for baseline permitting authority cost (unadjusted).***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 314 of 403 presumptive fee calculation) 234 . Several states suggested an approach similar to this in comments on the Tailoring Rule, however, their comments assumed we would not be exempting GHGs from the definition of regulated pollutants (for presumptive fee calculation), as we are proposing today.

We also solicit comment on whether we need to revise the presumptive minimum calculation provisions to account for GHGs costs if we exempt GHGs from the calculation of the presumptive minimum fee. The basis for this option would be that because most GHG sources that would be subject to title V permitting, whether due to GHGs or due for other reasons under the proposed NSPS and applicability provisions of the permitting rules (see 40 CFR 70.3 and 71.3) would have actual emissions of other regulated air pollutants subject to fees, and thus the cost of permitting these sources may be adequately accounted for without charging any additional fees specifically based on emissions of GHGs. We also note that support for this approach can be found in the current OMB-approved ICR for part 70, tables 14, 15 and 18, where the cost of permitting for permitting authorities is

234 At the current rate for part 70 of $46.73, this would result in a GHG fee adjustment of about $3.27, or a new rate of $50.00 per ton for each regulated pollutant (for presumptive fee calculation).***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 315 of 403 summarized, considering the effects of several recent EPA rulemakings that were conducted since the last ICR update. This proposal does not directly affect those states that do not rely on the presumptive minimum fee approach to show fee adequacy (those that charge more than the presumptive minimum fee), however non-presumptive fee states are still required to charge sufficient fees to recover all reasonable direct and indirect program costs. Part 70 allows the EPA to review state fee programs at any time to determine if they are collecting fees sufficient to cover their costs, whether or not states rely on the presumptively minimum fee approach. We are not requiring any additional detailed fee submittals from states at this time based on these proposed changes. Some states may conclude that they wish to revise their part 70 programs in response to this proposal either to revise their state fee schedules to prevent any possible collection of excessive fees (e.g., if they require any regulated pollutant subject to a section 111 standard to pay a fee) or to charge additional fees to sources because their presumptive minimum fee target has increased. We solicit comment on the most expeditious means for EPA to approve title V program revisions across the states once this proposal is finalized.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 316 of 403 In addition to the options for which comment is solicited above, there may be other viable options consistent with statutory and regulatory authority, principles, and concerns, that we have described in this proposal. For example, states have previously commented on a separate, lower presumptive fee per ton of GHG emissions). EPA invites states, local, and/or Tribal authorities to provide more refined data and/or information surrounding the unique costs associated with permitting GHG sources under this proposed rule, and other fee options such data supports. Notably, the regulatory text included today represents an option on which comments are solicited. EPA is also soliciting comment on other viable options described herein. EPA anticipates that sufficient information is provided in this preamble and the included regulatory text, to support EPA finalizing regulatory text on another option.

c. Revisions to the part 71 fee schedule As part of the promulgation of the final part 71 rule, the EPA performed a detailed analysis of the costs of developing and implementing the program and reviewed the inventory of emissions of regulated pollutants (for fee calculation) to determine the appropriate emission fee that would be sufficient to recover all direct and indirect programs costs – we set the fee at $32 per***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 317 of 403 ton, adjusted for inflation, times the emissions of regulated pollutant (for fee calculation). ( See Federal Operating Programs Fees, Revised Cost Analysis, February 1996; legacy docket A-93- 51, document number II-A-3.) For part 71, we also propose to exempt GHGs from the definition of regulated pollutant (for fee calculation), which is similar to the definition of regulated pollutants (for presumptive fee calculation) used in part 70, for the same reasons we have explained for part 70. In addition, for the same reasons we explained for part 70, we are proposing two options for revising the fee schedule of 40 CFR 71.9(c) to ensure that we continue to recover sufficient fees to fully fund the part 71 GHG permitting program. The bases for the options were described in more detail earlier in this proposal with respect to part 70 proposals and those also apply here to part 71.

First, the EPA (or delegate agency) burden hour assumptions we propose for each GHG-related permitting activity under part 71 are the same as we are proposing for states under the presumptive minimum fee provisions of part 70. 235 This option

235 See the supporting statement for the ICR renewal for part 71 approved by the Office of Management and Budget on June 13, 2012 for the 36 month period of June 30, 2012 through May 31, 2015. The ICR renewal for part 71 is identified as EPA ICR number***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 318 of 403 would rely on the following information. The labor rate assumption we propose for the EPA (or delegate agency) staff time under part 71 is the average hourly rate we assumed in the supporting statement for the recent part 71 ICR renewal of $52 per hour in 2011 dollars, including wages, benefits and overhead costs. We propose to determine the GHG fee adjustment for each GHG permitting program activity by multiplying the burden hour assumption we propose by the EPA (or delegate agency) labor rate we propose. Thus, for example, we propose a set fee to be paid by sources for each “completeness determination (for new permit or updated application” of $364 (7 hours times $52 per hour for the current period). Also, we propose to charge, for simplicity sake, the same set fees for GHG activities, whether performed by the EPA, a delegate agency, or by the EPA with contractor assistance. The appropriate set fees for all GHG permitting program activities performed for the source would be added to

the traditional fee that is determined based on emissions of each regulated pollutants (for fee calculation) to determine the

total fee for the source.

1713.10 and the ICR for part 71 has been assigned OMB control number 2060-0336. The assumptions of this part 71 ICR renewal for GHG burden are identical to those used for the part 70 ICR. See Table 12 of the part 71 supporting statement.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 319 of 403 The second option we propose for part 71 is to increase the emission fee by a modest amount for each regulated air pollutant, excluding GHGs. For simplicity sake, we propose to charge the same adjustment under this option that we propose for part 70, or 7 percent, which would be multiplied by annual part

71 fee in effect to calculate the revise fee rate 236 . The rationale for this approach is described in more detail earlier in this preamble during the part 70 discussion.

We also solicit comment on whether we could exclude GHG emissions from the calculation of the the annual part 71 fee for reasons similar to those we explained for part 70 (e.g., because permitting costs can be covered by the existing part 71 permit fee).

236 At the current rate for part 71 of $48.33, this would result in a GHG fee adjustment of $3.38, or a new rate of $51.710 per ton for each regulated pollutant (for fee calculation).***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 320 of 403

**XI. Impacts of the Proposed Action** A. What are the air impacts? As explained in the Regulatory Impact Analysis (RIA) for this proposed rule, available data indicate that, even in the absence of this rule, existing and anticipated economic conditions will lead electricity generators to choose new generation technologies that would meet the proposed standard without installation of additional controls. Therefore, based on the analysis presented in Chapter 5 of the RIA, the EPA projects that this proposed rule will result in negligible CO 2 emission changes, quantified benefits, and costs by 2020.

B. What are the energy impacts? This proposed rule is not anticipated to have a notable effect on the supply, distribution, or use of energy. As previously stated, the EPA believes that electric power companies would choose to build new EGUs that comply with the regulatory requirements of this proposal even in its absence, because of existing and expected market conditions. In addition, the EPA does not project any new coal-fired EGUs without CCS to be built in the absence of this proposal. C. What are the compliance costs?***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 321 of 403 The EPA believes this proposed rule will have no notable compliance costs associated with it, because electric power companies would be expected to build new EGUs that comply with the regulatory requirements of this proposal even in the absence of the proposal, due to existing and expected market conditions. The EPA does not project any new coal-fired EGUs without CCS to be built in the absence of the proposal. However, because somecompanies may choose to construct coal or other fossil fuelfired units, the RIA also analyzes project-level costs of a unit with and without CCS, to quantify the potential cost for a

fossil fuel-fired unit with CCS. D. How will this proposal contribute to climate change protection? As previously explained, the special characteristics of GHGs make it important to take initial steps to control the largest emissions categories without delay. Unlike most traditional air pollutants, GHGs persist in the atmosphere for time periods ranging from decades to millennia, depending on the gas. Fossil-fueled power plants emit more GHG emissions than any other stationary source category in the United States, and among new GHG emissions sources, the largest individual sources are in this source category. This proposed rule will limit GHG emissions from new***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 322 of 403 sources in this source category to levels consistent with current projections for new fossil-fuel-fired generating units. The proposed rule will also serve as a necessary predicate for the regulation of existing sources within this source category under CAA section 111(d). In these ways, the proposed rule will contribute to the actions required to slow or reverse the accumulation of GHG concentrations in the atmosphere, which is necessary to protect against projected climate change impacts

and risks. E. What are the economic and employment impacts? The EPA does not anticipate that this proposed rule will

result in notable CO 2 emission changes, energy impacts, monetized benefits, costs, or economic impacts by 2020. The owners of newly built electric generating units will likely choose technologies that meet these standards even in the absence of this proposal due to existing economic conditions as normal business practice. Likewise, the EPA believes this rule will not have any impacts on the price of electricity, employment or labor markets, or the U.S. economy. F. What are the benefits of the proposed standards? As previously stated, the EPA does not anticipate that the power industry will incur compliance costs as a result of this proposal and we do not anticipate any notable CO 2 emission***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 323 of 403 changes resulting from the rule. Therefore, there are no direct

monetized climate benefits in terms of CO 2 emission reductions associated with this rulemaking. However, by clarifying that in the future, new coal-fired power plants will be required to meet a particular performance standard, this rulemaking reduces uncertainty and may enhance the prospects for new coal-fired generation and the deployment of CCS, and thereby promote energy diversity. **XII. Request for Comments** We request comments on all aspects of the proposed rulemaking including the RIA. All significant comments received will be considered in the development and selection of the final rule. We specifically solicit comments on additional issues

under consideration as described below.

Measurement. We are requesting comment on requiring the use the following procedures that increase the precision of GHG

measurements: a. EPA Method 2F of 40 CFR part 60 for flow rate measurement during the relative accuracy test audit and performance testing. Method 2F provides velocity data for three dimensions and provides measurements more representative of actual gas flow rates than EPA Method 2 or 2G of 40 CFR part 60.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 324 of 403 b. EPA Method 2H of 40 CFR part 60 or Conditional Test Method (CTM)-041 (see:http://www.epa.gov/airmarkets/emissions/docs/square-ducts-walleffects-test-method-ctm-041.pdf ) to account for wall effects on for stack gas flow rate calculations during CEMS relative accuracy determinations and for performance testing. c. EPA Method 4 of 40 CFR part 60 to determine moisture for flow rate during CEMS relative accuracy determinations and for performance test calculations. d. EPA Method 3A of 40 CFR part 60 for CO 2 concentration measurement and for molecular weight determination during CEMS relative accuracy determinations or for performance testing. e. An ambient air argon concentration of 0.93 percent [1] and a molecular weight of 39.9 lb/lb-mol in calculating the dry gas molecular weight. f. A value for pi of 3.41159 when calculating the effective

area for circular stacks. g. A daily calibration drift cap no greater than 0.3 percent CO 2 for CO 2 CEMS. h. A maximum relative accuracy specification of 2.5 percent

for both CO 2 and flow rate measurement CEMS.

[1] http://www.physicalgeography.net/fundamentals/7a.html.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 325 of 403 i. Method 3B of 40 CFR part 60 in addition to Method 3A,

for CO 2 concentration measurement and for molecular weight determination during CEMS relative accuracy determinations or for performance testing.

Coal refuse. Due to the multiple environmental benefits of remediating coal refuse piles, we requested comment in the previous proposal on subcategorizing EGUs that burn over 75 percent coal refuse on an annual basis. Multiple commenters on the previous proposal supported the exemption citing the environmental benefits of remediating coal refuse piles. Commenters on the previous proposal also disagreed with any exemption, specifically siting the N 2 O emissions from fluidized bed boilers. Due to the environmental benefits of remediating coal refuse piles, the limited amount of coal refuse, and the

fact that a new coal refuse-fired EGU would have to be located in close proximity to the coal refuse pile, we are continuing to consider establishing a subcategory for coal refuse-fired EGUs and are requesting additional comments. Specifically, we are requesting additional information on the net environmental benefits of coal refuse-fired EGUs, and in the event we do establish a coal refuse-fired subcategory, what the emissions standard for that subcategory should be. One commenter on the previous proposal stated that existing coal refuse piles are***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 326 of 403 naturally combusting at a rate of 0.3 percent annually. We are requesting comment on assuming this rate of natural combustion and the proper approach to accounting for naturally occurring emissions from coal refuse piles. Compressed Air Energy Storage (CAES) Facilities. The EPA is considering and requesting comment on exempting stationary combustion turbines at compressed air energy storage facilities

from the CO 2 emissions standard. CAES technology involves two steps. Air is compressed by electric motor driven compressors during off-peak electricity demand hours and stored in a storage media (e.g., an underground cavern). Electricity is then generated during peak electricity demand periods by releasing the high

‐ pressure air, heating the air with natural gas, and expanding it through sequential turbines (expanders), which drive an electrical generator. Since natural gas is combusted in the stationary combustion turbine, a new CAES facility meeting the general applicability requirements would have to comply with an emissions standard. However, the use of stored energy complicates determining compliance with the proposed emission standards. Since we only expect a limited number of new CAES facilities, we have concluded that the new source review program is the appropriate mechanism to establish site specific GHG requirements for such sources.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 327 of 403 District Energy. Even though with the proposed definition of net-electric output it is unlikely that a district energy system would be subject to an emissions standard, we are considering and requesting comment on an appropriate method to recognize the environmental benefit of district energy systems. The steam or hot water distribution system of a district energy system located in urban areas, college and university campuses, hospitals, airports, and military installations eliminates the need for multiple, smaller boilers at individual buildings. A central facility typically has superior emission controls and consists of a few larger boilers facilitating more efficient operation than numerous separate smaller individual boilers. However, when the hot water or steam is distributed, approximately two to three percent of the thermal energy in the water and six to nine percent of the thermal energy in the steam is lost, reducing the net efficiency advantage. We are requesting comment on whether it is appropriate to divide the thermal output from district energy systems by a factor (i.e., 0.95 or 0.90) that would account for the net efficiency benefits of district energy systems. This approach would be similar to the proposed approach to how the electric output for CHP is considered when determining regulatory compliance and is consistent with the approach in the proposed amendments to the***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 328 of 403 combustion turbine NSPS (77 FR 52554). We request that comments include technical analysis of the net benefits in support of any

conclusions. Emergency conditions . We are requesting comment on excluding electricity generated as a result of a grid emergency declared by the Regional Transmission Organizations (RTO), Independent System Operators (ISO) or control area Administrator (e.g., grid voltage would drop below acceptable levels and the affected facility is the only facility with additional available capacity) from counting as net sales when determining applicability as an EGU. While the proposed 3 year average electric sales applicability provides significant flexibility for simple cycle turbines, we are considering including the emergency conditions exemption to allow facilities designed with the intent to sell less than 1/3 of their potential electric output to continue to generate electricity during a grid emergency without such generation counting towards the 1/3 sales applicability criterion. In the original electric utility NSPS rulemaking, the EPA recognized that emergency periods do occur from unplanned EGU outages, transmission outages or surging customer demand loads. Such occurences may require that all available operable EGUs interconnected to the electrical grid supply power to the grid. Provisions were added to 40 CFR 60***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 329 of 403 subpart Da to address emergency conditions when continued operation of an EGU with a malfunctioning flue gas desulfurization (FGD) system is acceptable and not considered a

violation of the SO 2 emissions standard. These conditions require that all available capacity from the power company’s other EGUs is being used and all available purchase power from interconnected power companies is being obtained. In this case, the EPA concluded that the broader benefits of operating the power plant with the malfunctioning FGD system to generate electrical power during emergency conditions in order to ensure uninterrupted electricity supply to the public outweigh any adverse impacts from a short-term increase in SO 2 emission to the atmosphere from the power plant. Initial Design Efficiency Test. We are considering and requesting comment on requiring an initial performance test forstationary combustion turbines in addition to the 12-operatingmonth rolling average standard. Requiring an initial compliance test that is numerically more stringent than the annual standard for new combined cycle facilities would insure that the most efficient stationary combustion turbines are installed. The less stringent 12-month rolling average standard would be set at a level that would take into account actual operating conditions.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 330 of 403 Integrated Equipment. The proposed affected facility definition includes the stationary combustion turbine/steam generating unit “plus any integrated equipment that provides electricity or useful thermal output.” We are considering and requesting comment on also including co-located non-emitting energy generation equipment that is not integrated into the operation of the affected facility in the definition of the affected facility. This approach would provide additional flexibility, lower compliance costs, and recognize the environmental benefit of non-emitting sources of electricity and not limit options to solar thermal feedwater heating. The definition would include the additional language “or co-located non-emitting energy generation included in the facility operating permit.” This would permit the use of co-located photovoltaic solar power, wind turbines, and other non-emitting energy generation as means for achieving compliance with the emission standards. Since integrated solar thermal feedwater heating is primarily only a feasible option for facilities that operate daily, this approach would expand options for more intermittent intermediate load generators to efficiently integrate non-emitting energy generation into their design. Net-output-based standards. We are considering and requesting comment on adding an optional net-output based***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 331 of 403 standard for each subcategory. As described in the previous proposal, net output is the combination of the gross electrical output of the electric generating unit minus the parasitic power requirements. A parasitic load for an electric generating unit is any of the loads or devices powered by electricity, steam, hot water, or directly by the gross output of the electric generating unit that does not contribute electrical, mechanical, or thermal output. In general, less than 7.5 percent of non-IGCC and non-CCS coal-fired station power output, approximately 15 percent of non-CSS IGCC-based coal-fired station power output and about 2.5 percent of non-CCS combined cycle station power output is used internally by parasitic energy demands, but the amount of these parasitic loads vary from source to source. Reasons for using net output include (1) recognizing the efficiency gains of selecting EGU designs and control equipment that require less auxiliary power, (2) selecting fuels that require less emissions control equipment, and (3) recognizing the environmental benefit of higher efficiency motors, pumps, and fans. While the EPA has concluded that the net power supplied to the end user is a better indicator of environmental performance than gross output from the power producer, we only have CEMS emissions data reported on a gross output basis. In addition, for facilities that coproduce chemicals and other Comment [A126]: It would be helpful if EPA could explain why it only has CEMS emission data reported on a gross output basis and why the agency is not able to move to a more optimal parasitic accounting approach.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 332 of 403 useful byproducts, accurate accounting of the parasitic loads could be problematic. The optional net-output based standard would have the most impact for non-IGCC-based coal-fired EGUs.While the net output based emissions rate for all non-CCS coalfired generation is similar, IGCC facilities have substantially larger parasitic loads and correspondingly lower gross emissions rates. The optional net-output based CO 2 emissions rate for steam generating units and IGCC facilities corresponding to an emissions rate of 1,100 lb CO 2 /MWh on a gross basis would be 1,400 lb CO 2 /MWh. The net-output based rate for stationary combustion turbines would be 1,030 lb CO 2 /MWh and 1,130 lb

CO 2 /MWh for the large and small subcategory respectively.

Other GHGs. Today’s proposed rule would require continuous

measurement of CO 2 from fossil fuel-fired EGUs. Other GHGs, such as methane (CH 4 ) and nitrous oxide (N 2 O) are not included in the proposed emission standards and are also not required to be measured and reported by affected EGUs as part of today’s proposal, even though their 100-year global warming potential is 21 to 310 times greater than that of CO 2 , because their emissions from EGUs are believed to be negligible when compared to CO 2 emissions. We request comment on the appropriateness, technique, and frequency (one-time or periodic, but not continuous) of measurement and reporting of CH 4 and N 2 O emissions from fossil***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 333 of 403 fuel-fired EGUs as part of the proposed emissions standard. Receipt of this data would enhance understanding of total GHG emissions from EGUs and could aid future policy decisions regarding whether these GHGs should be included in a revised emission standard, as part of 8-year NSPS review and potential revision cycle.

Violations . We are proposing that the calculation of the number of daily violations within an averaging period be determined using the following methodology. The number of daily violations in a 12-operating-month or 60-operating-month averaging period would be the number of operating days in that averaging period. However, if a violation occurs directly following the previous 12-operating-month or 60-operating-month averaging period, daily violations would not double count operating days that were determined as violations under the previous averaging period. For example, if a facility operations 10 days of month for 12 months and exceeds the emissions standard. The initial violation would constitute 120 daily violations. If the facility operated 20 days the following month and was still in excess of the emissions standard, 20 additional daily violations would result for a total of 140 daily violations. We are requesting comment on this determination of***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 334 of 403 daily violations for owners/operators that exceeds either a 12- operating-month or 60-operating-month standard. **XIII. Statutory and Executive Order Reviews** A. Executive Order 12866, Regulatory Planning and Review, and Executive Order 13563, Improving Regulation and Regulatory

Review Under Executive Order (EO) 12866 (58 FR 51,735, October 4, 1993), this action is a “significant regulatory action” because it “raises novel legal or policy issues arising out of legal mandates”. Accordingly, the EPA submitted this action to the Office of Management and Budget (OMB) for review under Executive Orders 12866 and 13563 (76 FR 3821, January 21, 2011) and any changes made in response to OMB recommendations have been documented in the docket for this action. In addition, the EPA prepared an analysis of the potential costs and benefits associated with this action. This analysis is contained in the Regulatory Impact Analysis for the Standards of Performance for

Greenhouse Gas Emissions for New Fossil Fuel-Fired Electric Utility Steam Generating Units and Stationary Combustion

Turbines. The EPA believes this rule will have no notable compliance costs associated with it over a range of likely sensitivity conditions because electric power companies would choose to***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 335 of 403 build new EGUs that comply with the regulatory requirements of this proposal even in the absence of the proposal, because of existing and expected market conditions. (See the RIA for further discussion of sensitivities). The EPA does not project any new coal-fired EGUs without CCS to be built in the absence of this proposal. However, because some companies may choose to construct coal or other fossil fuel-fired units, the RIA also analyzes project-level costs of a unit with and without CCS, to quantify the potential cost for a fossil fuel-fired unit with

CCS. B. Paperwork Reduction Act The information collection requirements in this proposed rule have been submitted for approval to the Office of Management and Budget (OMB) under the Paperwork Reduction Act , 44 U.S.C. 3501 et seq . The Information Collection Request (ICR) document prepared by the EPA has been assigned the EPA ICR

number 2465.01. This proposed action would impose minimal new information collection burden on affected sources beyond what those sources would already be subject to under the authorities of CAA parts 75 and 98. OMB has previously approved the information collection requirements contained in the existing part 75 and 98 regulations (40 CFR part 75 and 40 CFR part 98) under the***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 336 of 403 provisions of the Paperwork Reduction Act , 44 U.S.C. 3501 et

seq . and has assigned OMB control numbers 2060-0626 and 2060- 0629, respectively. Apart from certain reporting costs based on requirements in the NSPS General Provisions (40 CFR part 60, subpart A), which are mandatory for all owners/operators subject to CAA section 111 national emission standards, there are no new information collection costs, as the information required by this proposed rule is already collected and reported by other regulatory programs. The recordkeeping and reporting requirements are specifically authorized by CAA section 114 (42 U.S.C. 7414). All information submitted to the EPA pursuant to the recordkeeping and reporting requirements for which a claim of confidentiality is made is safeguarded according to Agency policies set forth in 40 CFR part 2, subpart B. The EPA believes that electric power companies will choose to build new EGUs that comply with the regulatory requirements of this proposal because of existing and expected market conditions. The EPA does not project any new coal-fired EGUs that commence construction after this proposal to commence operation over the three-year period covered by this ICR. We

estimate that 17 new affected NGCC units would commence operation during that time period. As a result of this proposal, those units would be required to prepare a summary report, which***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 337 of 403 includes reporting of excess emissions and downtime, every six

months. When a malfunction occurs, sources must report them according to the applicable reporting requirements of 40 CFR part 60, subpart Da or subpart KKKK. An affirmative defense to civil penalties for exceedances of emission limits that are caused by malfunctions is available to a source if it can demonstrate that certain criteria and requirements are

satisfied. The criteria ensure that the affirmative defense is available only where the event that causes an exceedance of the

emission limit meets the narrow definition of malfunction (sudden, infrequent, not reasonably preventable, and not caused by poor maintenance or careless operation) and where the source took necessary actions to minimize emissions. In addition, the source must meet certain notification and reporting requirements. For example, the source must prepare a written root cause analysis and submit a written report to the Administrator documenting that it has met the conditions and requirements for assertion of the affirmative defense. To provide the public with an estimate of the relative magnitude of the burden associated with an assertion of affirmative defense, the EPA has estimated what the notification, recordkeeping, and reporting requirements***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 338 of 403 associated with the assertion of the affirmative defense might entail. The EPA’s estimate for the required notification, reports, and records, including the root cause analysis, associated with a single incident totals approximately totals $3,141, and is based on the time and effort required of a source to review relevant data, interview plant employees, and document the events surrounding a malfunction that has caused an

exceedance of an emission limit. The estimate also includes time to produce and retain the record and reports for submission to the EPA. The EPA provides this illustrative estimate of this burden, because these costs are only incurred if there has been a violation, and a source chooses to take advantage of the

affirmative defense. Given the variety of circumstances under which malfunctions could occur, as well as differences among sources' operation and maintenance practices, we cannot reliably predict the severity and frequency of malfunction-related excess emissions events for a particular source. It is important to note that the EPA has no basis currently for estimating the number of malfunctions that would qualify for an affirmative defense. Current historical records would be an inappropriate basis, as this rule applies only to sources built in the future. Of the number of excess emissions events that may be reported by source operators, only***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 339 of 403 a small number would be expected to result from a malfunction, and only a subset of excess emissions caused by malfunctions would result in the source choosing to assert an affirmative defense. Thus, we believe the number of instances in which source operators might be expected to avail themselves of the affirmative defense will be extremely small. In fact, we estimate that there will be no such occurrences for any new sources subject to 40 CFR part 60, subpart Da or subpart KKKK over the three-year period covered by this ICR. We expect to gather information on such events in the future, and will revise

this estimate as better information becomes available.

The annual information collection burden for this collection consists only of reporting burden as explained above. The reporting burden for this collection (averaged over the first three years after the effective date of the standards) is estimated to be $15,570 and 396 labor hours. This estimate includes semi-annual summary reports which include reporting of

excess emissions and downtime. All burden estimates are in 2010 dollars. Average burden hours per response are estimated to be 16.5 hours. The total number of respondents over the three-year ICR period is estimated to be 36. Burden is defined at 5 CFR 1320.3(b).***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 340 of 403 An agency may not conduct or sponsor, and a person is not required to respond to, a collection of information unless it displays a currently valid OMB control number. The OMB control numbers for the EPA's regulations in 40 CFR are listed in 40 CFR part 9. To comment on the Agency's need for this information, the accuracy of the provided burden estimates, and any suggested methods for minimizing respondent burden, the EPA has established a public docket for this rule, which includes this ICR, under Docket ID number EPA-HQ-OAR-2013-0495. Submit any

comments related to the ICR to the EPA and OMB. See **ADDRESSES** section at the beginning of this notice for where to submit

comments to the EPA. Send comments to OMB at the Office of Information and Regulatory Affairs, Office of Management and Budget, 725 17th Street, NW, Washington, DC 20503, Attention: Desk Officer for the EPA. Since OMB is required to make a decision concerning the ICR between 30 and 60 days after [INSERT DATE OF PUBLICATION IN THE FEDERAL REGISTER], a comment to OMB is best assured of having its full effect if OMB receives it by [INSERT DATE 30 DAYS AFTER PUBLICATION IN THE FEDERAL REGISTER]. The final rule will respond to any OMB or public comments on the information collection requirements contained in this proposal. C. Regulatory Flexibility Act as Amended by the Small Business***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 341 of 403 Regulatory Enforcement Fairness Act of 1996, 5 U.S.C. et seq. The Regulatory Flexibility Act (RFA) generally requires an agency to prepare a regulatory flexibility analysis of any rule subject to notice and comment rulemaking requirements under the Administrative Procedure Act or any other statute unless the agency certifies that the rule will not have a significant economic impact on a substantial number of small entities. Small entities include small businesses, small organizations, and small governmental jurisdictions. For purposes of assessing the impacts of this rule on small entities, small entity is defined as: (1) A small business that is defined by the SBA’s regulations at 13 CFR 121.201 (for the electric power generation industry, the small business size standard is an ultimate parent entity defined as having a total electric output of 4 million MWh or less in the previous fiscal year. The NAICS codes for the affected industry are in Table 5 below); (2) A small governmental jurisdiction that is a government of a city, county, town, school district or special district with a population of less than 50,000; and (3) A small organization that is any not-for-profit enterprise which is independently owned and operated and is not

dominant in its field.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 342 of 403 **Table 5. Potentially Regulated Categories and Entities a** 

**Category NAICS**  **Code Examples of Potentially Regulated**  **Entities**

Industry 221112 Fossil fuel electric power generating units.

Federal Government 221112 b Fossil fuel electric power generating units owned by the federal government.

State/Local Government 221112 b Fossil fuel electric power generating units owned by municipalities.

Tribal Government 921150 Fossil fuel electric power generating units in Indian Country.

a Include NAICS categories for source categories that own and operate electric power generating units (includes boilers and stationary combined cycle combustion turbines). b Federal, state, or local government-owned and operated establishments are classified according to the activity in which they are engaged. After considering the economic impacts of this proposed rule on small entities, I certify that this action will not have a significant economic impact on a substantial number of small

entities. We do not include an analysis of the illustrative impacts on small entities that may result from implementation of this proposed rule because we do not anticipate any compliance costs over a range of likely sensitivity conditions as a result of this proposal. Thus the cost-to-sales ratios for any affected***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 343 of 403 small entity would be zero costs as compared to annual sales revenue for the entity. The EPA believes that electric power companies will choose to build new EGUs that comply with the regulatory requirements of this proposal because of existing and expected market conditions. (See the RIA for further discussion of sensitivities). The EPA does not project any new coal-fired EGUs without CCS to be built. Accordingly, there are no anticipated economic impacts as a result of this proposal. Nevertheless, the EPA is aware that there is substantial interest in this rule among small entities (municipal and rural electric cooperatives). In light of this interest, prior to the April 13, 2012 proposal (77 FR 22392), the EPA determined to seek early input from representatives of small entities while formulating the provisions of the proposed regulation. Such outreach is also consistent with the President’s January 18, 2011 Memorandum on Regulatory Flexibility, Small Business, and Job Creation, which emphasizes the important role small businesses play in the American economy. This process has enabled the EPA to hear directly from these representatives, at a very preliminary stage, about how it should approach the complex question of how to apply Section 111 of the CAA to the regulation of GHGs from these source categories. The EPA’s outreach regarded planned actions for new and existing sources,***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 344 of 403 but only new sources would be affected by this proposed action. The EPA conducted an initial outreach meeting with small entity representatives on April 6, 2011. The purpose of the meeting was to provide an overview of recent EPA proposals impacting the power sector. Specifically, overviews of the Transport Rule, the Mercury and Air Toxics Standards, and the Clean Water Act 316(b) Rule proposals were presented. The EPA conducted outreach with representatives from 20 various small entities that potentially would be affected by this rule. The representatives included small entity municipalities, cooperatives, and private investors. We distributed outreach materials to the small entity representatives; these materials included background, an overview of affected sources and GHG emissions from the power sector, an overview of CAA section 111, an assessment of CO 2 emissions control technologies, potential impacts on small entities, and a summary of the listening sessions. We met with eight of the small entity representatives, as well as three participants from organizations representing power producers, on June 17, 2011, to discuss the outreach materials, potential requirements of the rule, and regulatory areas where the EPA has discretion and could potentially provide flexibility.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 345 of 403 A second outreach meeting was conducted on July 13, 2011. We met with nine of the small entity representatives, as well as three participants from organizations representing power producers. During the second outreach meeting, various small entity representatives and participants from organizations representing power producers presented information regarding issues of concern with respect to development of standards for GHG emissions. Specifically, topics suggested by the small entity representatives and discussed included: boilers with limited opportunities for efficiency improvements due to NSR complications for conventional pollutants; variances per kilowatt-hour and in heat rates over monthly and annual operations; significance of plant age; legal issues; importance of future determination of carbon neutrality of biomass; and differences between municipal government electric utilities and

other utilities. While formulating the provisions of this proposed regulation, the EPA also considered the input provided in the over 2.5 million public comments on the April 13, 2012 proposed rule (77 FR 22392). We invite comments on all aspects of the proposal and its impacts, including potential adverse impacts,

on small entities.

D. Unfunded Mandates Reform Act of 1995***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 346 of 403 This proposed rule does not contain a federal mandate that may result in expenditures of $100 million or more for State, local, and tribal governments, in the aggregate, or the private sector in any one year. The EPA believes this proposed rule will have no compliance costs associated with it over a range of likely sensitivity conditions because electric power companies will choose to build new EGUs that comply with the regulatory requirements of this proposal because of existing and expected market conditions. (See the RIA for further discussion of sensitivities). The EPA does not project any new coal-fired EGUs

without CCS to be built. Thus, this proposed rule is not subject to the requirements of sections 202 or 205 of UMRA. This proposed rule is also not subject to the requirements of section 203 of UMRA because it contains no regulatory requirements that might significantly or uniquely affect small

governments. In light of the interest in this rule among governmental entities, the EPA initiated consultations with governmental entities prior to the April 13, 2012 proposal (77 FR 22392). The EPA invited the following 10 national organizations representing state and local elected officials to a meeting held on April 12, 2011, in Washington DC: 1) National Governors Association; 2) National Conference of State Legislatures, 3) Council of State***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 347 of 403 Governments, 4) National League of Cities, 5) U.S. Conference of Mayors, 6) National Association of Counties, 7) International City/County Management Association, 8) National Association of Towns and Townships, 9) County Executives of America, and 10) Environmental Council of States. These 10 organizations representing elected state and local officials have been identified by the EPA as the “Big 10” organizations appropriate to contact for purpose of consultation with elected officials. The purposes of the consultation were to provide general background on the proposal, answer questions, and solicit input from state/local governments. The EPA’s consultation regarded planned actions for new and existing sources, but only new sources would be affected by this proposed action. During the meeting, officials asked clarifying questions regarding CAA section 111 requirements and efficiency improvements that would reduce CO 2 emissions. In addition, they expressed concern with regard to the potential burden associated with impacts on state and local entities that own/operate affected utility boilers, as well as on state and local entities with regard to implementing the rule. Subsequent to the April 12, 2011 meeting, the EPA received a letter from the National Conference of State Legislatures. In that letter, the National Conference of State Legislatures urged the EPA to ensure that***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 348 of 403 the choice of regulatory options maximizes benefit and minimizes implementation and compliance costs on state and local governments; to pay particular attention to options that would provide states with as much flexibility as possible; and to take into consideration the constraints of the state legislative

calendars and ensure that sufficient time is allowed for state actions necessary to come into compliance. While formulating the provisions of this proposed regulation, the EPA also considered the input provided in the over 2.5 million public comments on the April 13, 2012 proposed rule (77 FR 22392). E. Executive Order 13132, Federalism This proposed action does not have federalism implications. It would not have substantial direct effects on the States, on the relationship between the national government and the States, or on the distribution of power and responsibilities among the various levels of government, as specified in EO 13132. This proposed action would not impose substantial direct compliance costs on state or local governments, nor would it preempt state law. Thus, Executive Order 13132 does not apply to this action. Prior to the April 13, 2012 proposal (77 FR 22392), the EPA consulted with state and local officials in the process of developing the proposed rule to permit them to have meaningful***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 349 of 403 and timely input into its development. The EPA’s consultation regarded planned actions for new and existing sources, but only new sources would be affected by this proposed action. The EPA met with 10 national organizations representing state and local elected officials to provide general background on the proposal, answer questions, and solicit input from state/local governments. The UMRA discussion in this preamble includes a description of the consultation. While formulating the provisions of this proposed regulation, the EPA also considered the input provided in the over 2.5 million public comments on the April 13, 2012 proposed rule (77 FR 22392). In the spirit of EO 13132, and consistent with the EPA policy to promote communications between the EPA and state and local governments, the EPA specifically solicits comment on this proposed action

from state and local officials. F. Executive Order 13175, Consultation and Coordination with

Indian Tribal Governments Subject to the EO 13175 (65 FR 67249, November 9, 2000) the EPA may not issue a regulation that has tribal implications, that imposes substantial direct compliance costs, and that is not required by statute, unless the federal government provides the funds necessary to pay the direct compliance costs incurred by tribal governments, or the EPA consults with tribal officials***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 350 of 403 early in the process of developing the proposed regulation and develops a tribal summary impact statement. The EPA has concluded that this proposed action would not have tribal implications. It would neither impose substantial direct compliance costs on tribal governments, nor preempt Tribal law. This proposed rule would impose requirements on owners and operators of new EGUs. The EPA is aware of three coal-fired EGUs located in Indian Country but is not aware of any EGUs owned or operated by tribal entities. The EPA notes that this proposal does not affect existing sources such as the three coal-fired EGUs located in Indian Country, but addresses

CO 2 emissions for new EGU sources only.

Because the EPA is aware of Tribal interest in this proposed rule, prior to the April 13, 2012 proposal (77 FR 22392), the EPA offered consultation with tribal officials early in the process of developing the proposed regulation to permit them to have meaningful and timely input into its development. The EPA’s consultation regarded planned actions for new and existing sources, but only new sources would be affected by this proposed action.

Consultation letters were sent to 584 tribal leaders. The letters provided information regarding the EPA’s development of NSPS and emission guidelines for EGUs and offered consultation.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 351 of 403 A consultation/outreach meeting was held on May 23, 2011, with the Forest County Potawatomi Community, the Fond du Lac Band of Lake Superior Chippewa Reservation, and the Leech Lake Band of Ojibwe. Other tribes participated in the call for information gathering purposes. In this meeting, the EPA provided background information on the GHG emission standards to be developed and a summary of issues being explored by the Agency. Tribes suggested that the EPA consider expanding coverage of the GHG standards to include combustion turbines, lowering the 250 MMBtu per hour heat input threshold so as to capture more EGUs, and including

credit for use of renewables. The tribes were also interested in the scope of the emissions averaging being considered by the Agency (e.g., over what time period, across what units). In addition, the EPA held a series of listening sessions on this proposed action. Tribes participated in a session on February 17, 2011 with the state agencies, as well as in a separate session with tribes on April 20, 2011. While formulating the provisions of this proposed regulation, the EPA also considered the input provided in the over 2.5 million public comments on the April 13, 2012 proposed rule (77 FR 22392). The EPA will also hold additional meetings with tribal

environmental staff to inform them of the content of this***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 352 of 403 proposal as well as provide additional consultation with tribal elected officials where it is appropriate. We specifically solicit additional comment on this proposed rule from tribal

officials. G. Executive Order 13045, Protection of Children from Environmental Health Risks and Safety Risks The EPA interprets EO 13045 (62 FR 19885, April 23, 1997) as applying to those regulatory actions that concern health or safety risks, such that the analysis required under section 5- 501 of the Order has the potential to influence the regulation. This proposed action is not subject to EO 13045 because it is based solely on technology performance. The proposal is not expected to produce notable changes in emissions of greenhouse gases or other pollutants but does encourage the current trend towards cleaner generation, helping to protect air quality and children's health. The Agency recognizes that children are among the groups most vulnerable to climate change impacts and the public is invited to submit comments or identify peer reviewed studies relevant to this proposal. H. Executive Order 13211, Actions Concerning Regulations That Significantly Affect Energy Supply, Distribution, or Use This proposed action is not a “significant energy action” as defined in EO 13211 (66 FR 28355 (May 22, 2001)) because it***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 353 of 403 is not likely to have a significant adverse effect on the supply, distribution, or use of energy. This proposed action is not anticipated to have notable impacts on emissions, costs or energy supply decisions for the affected electric utility industry. I. National Technology Transfer and Advancement Act Section 12(d) of the NTTAA of 1995 (Public Law No. 104-113; 15 U.S.C. 272 note) directs the EPA to use Voluntary Census Standards in their regulatory and procurement activities unless to do so would be inconsistent with applicable law or otherwise impractical. Voluntary consensus standards are technical standards (e.g., materials specifications, test methods, sampling procedures, business practices) developed or adopted by one or more voluntary consensus bodies. The NTTAA directs the EPA to provide Congress, through annual reports to the OMB, with explanations when an agency does not use available and applicable VCS. This proposed rulemaking involves technical standards. The EPA cites the following standards in this proposed rule: D5287- 08 (Standard Practice for Automatic Sampling of Gaseous Fuels), D4057-06 (Standard Practice for Manual Sampling of Petroleum and Petroleum Products), and D4177-95(2010) (Standard Practice for Automatic Sampling of Petroleum and Petroleum Products). The EPA***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 354 of 403 is proposing use of Appendices B, D, F, and G to 40 CFR part 75; these Appendices contain standards that have already been

reviewed under the NTTAA. The EPA welcomes comments on this aspect of the proposed rulemaking and, specifically, invites the public to identify potentially-applicable VCS and to explain why such standards

should be used in this action.

J. Executive Order 12898: Federal Actions to Address Environmental Justice in Minority Populations and Low-Income Populations Executive Order 12898 (59 FR 7629, February 16, 1994) establishes federal executive policy on environmental justice. Its main provision directs federal agencies, to the greatest extent practicable and permitted by law, to make environmental justice part of their mission by identifying and addressing, as appropriate, disproportionately high and adverse human health or environmental effects of their programs, policies, and activities on minority populations and low-income populations in

the U.S. This proposed rule limits GHG emissions from new fossil fuel-fired EGUs by establishing national emission standards for

CO 2 . The EPA has determined that this proposed rule would not result in disproportionately high and adverse human health or***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 355 of 403 environmental effects on minority, low-income, and indigenous populations because it increases the level of environmental protection for all affected populations without having any disproportionately high and adverse human health or environmental effects on any population, including any minority, low-income or indigenous populations.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** **Standards of Performance for Greenhouse Gas Emissions from New Stationary Sources: Electric Utility Generating Units**  Page 340 of 403

List of Subjects in 40 CFR Part 60 Environmental protection, Administrative practice and procedure, Air pollution control, Intergovernmental relations, Reporting and recordkeeping requirements.

___________________ Dated:[add signature date]

____________________ [Insert name here] [Acting?] Administrator***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 341 of 403 For the reasons stated in the preamble, title 40, chapter I, part 60, 70, 71, and 98 of the Code of the Federal Regulations is proposed to be amended as follows: **PART 60--[AMENDED]** 1. The authority citation for part 60 continues to read as

follows: Authority: 42 U.S.C. 7401, et seq. **Subpart Da-—[Amended]**

2. Section 60.46Da is revised to read as follows: **§60.46Da Standards for carbon dioxide (CO 2**  **)**

(a) Your electric utility steam generating unit or IGCC electric utility steam generating unit is subject to this section if construction commenced on or after [INSERT DATE OF PUBLICATION IN THE FEDERAL REGISTER], and the affected facility meets the conditions specified in paragraph (1) and (2) of this subsection, except as specified in paragraph (b) of this

section.

(1) The affected facility burns fossil fuel for more than 10.0 percent of the average annual heat input during any 3 consecutive calendar years.

(2) The affected facility supplies more than one-third of its potential electric output and more than 219,000 MWh net-***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 342 of 403 electrical output to a utility power distribution system for

sale.

(b) The following EGUs are not subject to this section: (1) The proposed Wolverine EGU project described in Permit to Install No. 317-07 issued by the Michigan Department of Environmental Quality, Air Quality Division, effective June 29, 2011 (as revised July 12, 2011). (2) The proposed Washington County EGU project described in Air Quality Permit No. 4911-303-0051-P-01-0 issued by the Georgia Department of Natural Resources, Environmental Protection Division, Air Protection Branch, effective April 8, 2010, provided that a complete request for an applicability determination for the project has been submitted to [INSERT APPROPRIATE EPA CONTACT INFORMATION] no later than 120 days after [INSERT DATE OF FEDERAL REGISTER PUBLICATION] and EPA determines that construction had not commenced for NSPS purposes as of [INSERT DATE OF PUBLICATION FOR 111(a)(2) PURPOSES]. (3) The proposed Holcomb EGU project described in Air Emission Source Construction Permit 0550023 issued by the Kansas Department of Health and Environment, Division of Environment, effective December 16, 2010, provided that a complete request for an applicability determination for the project has been submitted to [INSERT APPROPRIATE EPA CONTACT INFORMATION] no later than 120 days after [INSERT DATE OF FEDERAL REGISTER***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 343 of 403 PUBLICATION] and EPA determines that construction had not commenced for NSPS purposes as of [INSERT DATE OF PUBLICATION FOR 111(a)(2) PURPOSES]. (c) No owner or operator of an affected facility subject to this section shall cause to be discharged into the atmosphere from the affected facility any gases that contain CO 2 in excess of the emissions limitation specified in either paragraph (1) or (2) of this subsection.

(1) 450 kilograms (kg) of CO 2 per megawatt-hour (MWh) of gross energy output (1,000 lb CO 2 /MWh) on a 12-operating month rolling average basis;or

(2) 480 kg of CO 2 per MWh of gross energy output (1,050 lb

CO 2 /MWh) on a 60-operating month rolling average basis.

(d) Your affected facility must be in compliance at all times with the applicable CO 2 emission limitation in paragraph (c) of this section for which you have elected to comply. However, compliance determinations are only to be made at the end of each operating month, as provided in paragraphs (1) and (2) of this subsection. For the purpose of this section, operating month means a calendar month during which any fuel is combusted in an affected facility at any time.

(1) If you elect to comply with the CO 2 emissions limitation in paragraph (c)(1) of this section, you must determine***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 344 of 403 compliance monthly by calculating the average CO 2 emissions rate for the affected facility at the end of each preceding 12- operating month period.

(2) If you elect to comply with the CO 2 emissions limitation in paragraph (c)(2) of this section, you must determine compliance monthly by calculating the average CO 2 emissions rate for the affected facility at the end of each preceding 60- operating month period.

(e) You must conduct an initial CO 2 emissions limitation determination for your affected facility within 30 days after the required number of operating months for the CO 2 emission limitation operating month compliance period that you have elected to comply with have been accumulated (i.e., 12-operating months or 60-operating months. The first operating month included in this compliance period is the month in which emissions reporting is required to begin under §75.64(a) of this chapter.

(f) You must monitor and collect data to demonstrate compliance with the CO 2 emissions limitation according to the requirements specified in paragraphs (f)(1) through (4) of this

section.

(1) You must prepare a monitoring plan in accordance with the applicable provisions in §§75.53(g) and (h) of this chapter.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 345 of 403 (2) You must measure the hourly CO 2 mass emissions from each affected facility using the procedures specified in paragraphs (f)(2)(i) through (vii) of this section, except as provided in paragraph (3) of this section.

(i) You must install, certify, operate, maintain, and

calibrate a CO 2 continuous emission monitoring system (CEMS) to directly measure and record CO 2 concentrations in the exhaust gases from your affected facility that are vented to the atmosphere and an exhaust gas flow rate monitoring system according to §75.10(a)(3)(i) of this chapter. If CO 2 concentration is measured on a dry basis, you must also install, certify, operate, maintain, and calibrate a continuous moisture monitoring system, according to §75.11(b) of this chapter.

(ii) For each monitoring system used to determine the CO 2 mass emissions, you must meet the applicable certification and quality assurance procedures in §75.20 of this chapter and appendices B and D to part 75 of this chapter.

(iii) You must use a laser device to measure each exhaust gas stack or duct dimensions at the flow monitor and the reference method sampling locations prior to the initial setup (characterization) of the flow monitor. For circular stacks, make three determinations of the diameter and average the results. For rectangular stacks or ducts, make three***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 346 of 403 measurements of each dimension (i.e., depth and width) and average the results. If the flow rate monitor or reference method sampling site is relocated, repeat these measurements at

the new location.

(iv) Only unadjusted exhaust gas volumetric flow rates can be used to determine the hourly CO 2 mass emissions from the affected facility; the bias adjustment factors described in Section 7.6.5 of Appendix A to part 75 of this chapter cannot be applied to the exhaust gas flow rate data.

(v) If you elect to use Method 2 in Appendix A-1 to this part to perform the required relative accuracy test audits (RATAs) of the part 75 flow rate monitoring system, you must use a calibrated Type-S pitot tube or pitot tube assembly. Use of the default Type-S pitot tube coefficient is not permitted.

(vi) If two or more affected facilities share a common exhaust gas stack and are subject to the same CO 2 emissions limitation in paragraph (c) of this section, you may monitor the hourly CO 2 mass emissions at the common exhaust gas stack in place of monitoring each affected facility separately.

(vii) If the exhaust gases from the affected facilities are vented to the atmosphere through multiple stacks (or if the exhaust gases are routed to a common stack through multiple ducts and you elect to monitor in the ducts), you must monitor***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 347 of 403 the hourly CO 2 mass emissions and the “stack operating time” (as defined in §72.2 of this chapter) at each stack or duct separately.

(3) You must install, calibrate, maintain, and operate a sufficient number of watt meters to continuously measure and record the gross electrical output from the affected facility, and must meet the requirements specified in paragraphs (f)(4)(i) and (ii) of this section, as applicable.

(i) If your affected facility is a combined heat and power unit as defined in §60.42Da of this subpart, you must also install, calibrate, maintain, and operate meters to continuously determine and record the total useful recovered thermal energy. For process steam applications, this information includes steam flow rate, temperature, and pressure. If the combined heat and power unit has a direct mechanical drive application, you must submit a plan to the Administrator or delegated authority for approval of how gross energy output will be determined.

(ii) If two or more affected facilities ’ steam generating units serve a common electrical generator, you must apportion the combined hourly gross electrical output to each individual affected facility using a plan approved by the Administrator (e.g., using steam load or heat input to each affected facility).***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 348 of 403 (g) You must demonstrate compliance with the CO 2 emissions limitation using the procedures specified in paragraphs (g)(1) and (2) of this section.

(1) You must calculate the CO 2 mass emissions output-based rate for your affected facility using the hourly CO 2 mass emissions and gross energy output data determined and recorded according to the procedures specified in paragraph (f) of this section for each operating hour in the applicable operating month compliance period for the CO 2 emissions limitation (i.e., 12-operating months or 60-operating months), and the calculation procedures specified in paragraphs (g)(1)(i) through (v) of this

section.

(i) Use only operating hours in the operating month compliance period for which quality-assured data are obtained for all parameters used to determine the hourly CO 2 mass emissions. No operating hours in which the substitute data provisions of part 75 of this chapter are used for any of those parameters are to be included in the calculation. For the compliance determination calculation, you must obtain “valid” hourly CO 2 mass emission values for a minimum of 95 percent of the operating hours in the operating month compliance period for

the CO 2 emissions limitation applicable to the affected facility.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 349 of 403 (ii) Calculate the total CO 2 mass emissions by summing all of the valid hourly CO 2 mass emissions values determined for the applicable operating month compliance period interval. In a case for which exhaust gases from the affected facility are vented to the atmosphere through multiple stacks or ducts, the total CO 2 mass emissions for the affected facility is calculated by summing the total CO 2 mass emissions determined from each of the

individual stacks or ducts.

(iii) For each operating hour of the operating month compliance period used in paragraph (g)(1)(ii) of this section

to calculate the total CO 2 mass emissions, determine the affected facility’s corresponding hourly gross energy output using the appropriate definition in §60.42Da of this subpart for your affected facility. For an operating hour in which there is no gross electrical load, but there is mechanical or useful thermal output, you must still determine the gross energy output for that hour. In the case for which hourly CO 2 mass emissions are determined for a common stack, then the hourly gross energy output (electrical, thermal, and/or mechanical, as applicable) is determined by summing the hourly loads for the individual affected facility and the operating time is expressed as “stack operating hours” (as defined in §72.2 of this chapter).***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 3410 of 403 (iv) Calculate the total gross energy output by summing the hourly gross energy output values for the affected facility determined from paragraph (g)(1)(iii) of this section for all of the operating hours in the applicable operating month compliance period interval.

(v) Calculate the CO 2 mass emissions output-based rate for the applicable operating month compliance period interval by dividing the total CO 2 mass emissions value from paragraph (g)(1)(ii) of this section by the total gross energy output value from paragraph (g)(1)(iv) of this section.

(2) Compliance with the CO 2 emissions limitation in paragraph (c) of this section is determined as specified in paragraphs (g)(2)(i) and (ii) of this section using the CO 2 mass emissions output-based rate for your affected facility determined in paragraph (g)(1) of this section.

(i) If the CO 2 mass emissions output-based rate for the affected facility is less than or equal to the CO 2 emissions limitation in paragraph (c) of this section applicable to your affected facility, then the affected facility is determined to be in compliance with the CO 2 emissions limitation. If compliance

with the CO 2 emissions limitation is attained at a common stack for two or more affected facilities subject to the same CO 2***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 3411 of 403 emissions limitation, each affected facility sharing the stack is considered to be in compliance.

(ii) If the CO 2 mass emissions output-based rate for the affected facility is greater than the CO 2 emissions limitation in paragraph (c) of this section applicable to your affected facility, then the affected facility is determined to have

excess emissions.

(h) You must prepare and submit notifications and reports according to paragraphs (h)(1) through (4) of this section.

(1) You must prepare and submit the notifications specified in §§60.7(a)(1) and (a)(3) and §60.19 of this part, as applicable to your affected facility.

(2) You must prepare and submit notifications specified in §75.61 of this chapter, as applicable to your affected facility.

(3) You must submit electronic quarterly reports according to the requirements specified in paragraphs (h)(3)(i) through (iii) of this section.

(i) Initially, after the required number of operating

months for the CO 2 emission limitation operating month compliance period that you have elected to comply with have been accumulated (i.e., 12-operating months or 60-operating months), a report for the calendar quarter that includes the twelfth (or sixtieth) operating month must be submitted no later than 30***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 3412 of 403 days after the end of that quarter. Thereafter, a report for each subsequent calendar quarter must be submitted no later than 30 days after the end of the quarter.

(ii) Each quarterly report must include the information specified in paragraphs (h)(3)(ii)(A) though (E) of this

section.

(A) Identification of the CO 2 emission limitation operating month compliance period you have elected to comply.

(B) Identification of any months in the calendar quarter that are not operating months.

(C) For each operating month in the calendar quarter, the corresponding average CO 2 mass emissions output-based rate for the applicable operating month compliance period interval, as determined according to paragraph (g) of this section.

(D) Percentage of valid CO 2 mass emission rates in each operating month compliance period (i.e., the total number of

valid CO 2 mass emission rates in that period divided by the total number of operating hours in that period, multiplied by 100 percent).

(E) Identification of any operating months in the calendar quarter with excess CO 2 emissions. (iii) The final quarterly report of each calendar year must contain the following:***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 3413 of 403 (A) Gross electric output sold to an electric grid over the 4 quarters of the calendar year; and (B) The potential electric output of the facility. (iv) Each electronic report must be submitted using the Emissions Collection and Monitoring Plan System (ECMPS) Client Tool provided by the Clean Air Markets Division in the EPA Office of Atmospheric Programs.

(4) You must meet all applicable reporting requirements and submit reports as required under subpart G of part 75 of this chapter.

(i) For each affected electric utility stream generating unit, you must maintain records according to paragraphs (i)(1) through (8) of this section.

(1) You must comply with the applicable recordkeeping requirements and maintain records as required under subpart F of part 75 of this chapter.

(2) You must maintain records of the calculations performed

to determine the total CO 2 mass emissions for each operating month, and averages for each operating month compliance period interval (i.e., 12-operating months or 60-operating months, as applicable to the CO 2 emissions limitations).***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 3414 of 403 (3) You must maintain records of the applicable data recorded and calculations performed used to determine the gross energy output for each operating month.

(4) You must maintain records of the calculations performed to determine the percentage of valid CO 2 mass emission rates in each operating month compliance period.

(5) You must maintain records of the calculations performed to assess compliance with each applicable CO 2 emissions limitation in paragraph (c) of this section.

(6) Your records must be in a form suitable and readily available for expeditious review.

(7) You must maintain each record for 5 years following the date of each occurrence, measurement, maintenance, corrective action, report, or record except those records required to demonstrate compliance with a 60-operating month compliance period. You must maintain records required to demonstrate compliance with a 60-operating month compliance period for at least 10 years following the date of each occurrence, measurement, maintenance, corrective action, report, or record.

(8) You must maintain each record on site for at least 2 years after the date of each occurrence, measurement, maintenance, corrective action, report, or record, according to***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 3415 of 403 §60.7. You may maintain the records off site and electronically for the remaining year(s) as required by this subpart.

(j) PSD and Thresholds for Greenhouse Gases.

(1) For purposes of 40 CFR 51.166(b)(49)(ii), with respect to GHG emissions from new EGUs, the “pollutant that is subject to the standard promulgated under section 111 of the Act” shall be considered to be the pollutant that otherwise is subject to regulation under the Act as defined in 40 CFR 51.166(b)(48) and in any SIP approved by the EPA that is interpreted to incorporate, or specifically incorporates, 40 CFR 51.166(b)(48). (2) For purposes of 40 CFR 52.21(b)(50)(ii), with respect to GHG emissions from new EGUs, the “pollutant that is subject to the standard promulgated under section 111 of the Act” shall be considered to be the pollutant that otherwise is subject to regulation under the Act as defined in 40 CFR 52.21(b)(49). (3) For purposes of 40 CFR 70.2, with respect to greenhouse gas emissions from new electric utility generating units, the “pollutant that is subject to any standard promulgated under section 111 of the Act” shall be considered to be the pollutant that otherwise is "subject to regulation" as defined in 40 CFR

70.2.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 3416 of 403 (4) For purposes of 40 CFR 71.2, with respect to greenhouse gas emissions from new electric utility generating units, the “pollutant that is subject to any standard promulgated under section 111 of the Act” shall be considered to be the pollutant that otherwise is "subject to regulation" as defined in 40 CFR 71.2. (k) For purposes of this section, the following definitions apply:

Gross energy output means: (1) For electric utility steam generating units constructed, reconstructed, or modified after May 3, 2011, the gross electrical or mechanical output from the affected facility minus any electricity used to power the feedwater pumps plus 75 percent of the useful thermal output measured relative to ISO conditions that is not used to generate additional electrical or mechanical output or to enhance the performance of the unit (i.e., steam delivered to an industrial process);

(2) For combined heat and power facilities constructed, reconstructed, or modified after May 3, 2011, where at least 20.0 percent of the total gross useful energy output consists of electric or direct mechanical output and 20.0 percent of the total gross useful energy output consists of thermal output, the gross electrical or mechanical output from the affected facility***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 3417 of 403 divided by 0.95 minus any electricity used to power the feedwater pumps plus 75 percent of the useful thermal output measured relative to ISO conditions that is not used to generate additional electrical or mechanical output or to enhance the performance of the unit ( i.e., steam delivered to an industrial process);

(3) For a IGCC electric utility generating unit constructed, reconstructed, or modified after May 3, 2011, the gross useful work performed is the gross electrical or mechanical output from the unit plus 75 percent of the useful thermal output measured relative to ISO conditions that is not used to generate additional electrical or mechanical output or to enhance the performance of the unit ( i.e., steam delivered to an industrial process).

Integrated gasification combined cycle electric utility steam generating unit or IGCC electric utility steam generating unit means an electric utility combined cycle gas turbine that is designed to burn fuels containing 50 percent (by heat input) or more solid-derived fuel not meeting the definition of natural gas plus any integrated equipment that provides electricity or useful thermal output to either the turbine engine and heat recovery steam generator or to power auxiliary equipment.. The***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 3418 of 403 Administrator may waive the 50 percent solid-derived fuel requirement during periods of the gasification system construction, startup and commissioning, shutdown, or repair. No solid fuel is directly burned in the unit during operation.

Net-electric output means (1) the gross electric sales to the utility power distribution system minus purchased power on a calendar year basis, or

(2) For combined heat and power facilities where at least 20.0 percent of the total gross useful energy output consists of electric or direct mechanical output and 20.0 percent of the total gross useful energy output consists of thermal output, net-electric output means the gross electric sales to the utility power distribution system minus purchased power of the thermal host facilities or facilities on a calendar year basis.

Potential electrical output capacity means 33 percent or the design net electric output efficiency time the maximum design heat input capacity of the steam generating unit, divided by 3,413 Btu/KWh, divided by 1,000 kWh/MWh, and multiplied by 8,760 hr/yr (e.g. , a 35 percent efficient steam generating unit with a 100 MW (341 MMBtu/h) fossil-fuel heat input capacity would have a 306,420 MWh 12 month potential electrical output capacity). For electric utility combined cycle gas turbines the potential electrical output capacity is determined on the basis***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 3419 of 403 of the fossil-fuel firing capacity of the steam generator exclusive of the heat input and electrical power contribution by the gas turbine.

Steam generating unit for facilities constructed, reconstructed, or modified before May 4, 2011, means any furnace, boiler, or other device used for combusting fuelfor the purpose of producing steam (including fossil-fuelfired steam generators associated with combined cycle gas turbines; nuclear steam generators are not included). For units constructed, reconstructed, or modified after May 3, 2011, steam generating unit means any furnace, boiler, or other device used for combusting fuel for the purpose of producing steam (including fossil-fuel-fired steam generators associated with combined cycle gas turbines; nuclear steam generators are not included) plus any integrated equipment that provides electricity or useful thermal output to either the boiler or to power auxiliary equipment.

* * * * * **Subpart KKKK-—[Amended]**

3. Section 60.4315 is revised to read as follows:

**§60.4315 What pollutants are regulated by this subpart?**

(a) The pollutants regulated by this subpart are nitrogen***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 3420 of 403 oxides (NO X ), sulfur dioxide (SO 2 ), and greenhouse gas. (b)(1) The greenhouse gas regulated by this subpart is carbon dioxide (CO 2 ). (2) PSD and Thresholds for Greenhouse Gases. (i) For purposes of 40 CFR 51.166(b)(49)(ii), with respect to GHG emissions from new EGUs, the “pollutant that is subject to the standard promulgated under section 111 of the Act” shall be considered to be the pollutant that otherwise is subject to regulation under the Act as defined in 40 CFR 51.166(b)(48) and in any SIP approved by the EPA that is interpreted to incorporate, or specifically incorporates, 40 CFR 51.166(b)(48). (ii) For purposes of 40 CFR 52.21(b)(50)(ii), with respect to GHG emissions from new EGUs, the “pollutant that is subject to the standard promulgated under section 111 of the Act” shall be considered to be the pollutant that otherwise is subject to regulation under the Act as defined in 40 CFR 52.21(b)(49). (iii) For purposes of 40 CFR 70.2, with respect to greenhouse gas emissions from new electric utility generating units, the “pollutant that is subject to any standard promulgated under section 111 of the Act” shall be considered to be the pollutant that otherwise is "subject to regulation" as

defined in 40 CFR 70.2.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 3421 of 403 (iv) For purposes of 40 CFR 71.2, with respect to greenhouse gas emissions from new electric utility generating units, the “pollutant that is subject to any standard promulgated under section 111 of the Act” shall be considered to be the pollutant that otherwise is "subject to regulation" as

defined in 40 CFR 71.2.

4. Section 60.4325 is added to read as follows:

**§60.4325 What CO 2**  **emissions standard must I meet?**

For each affected EGU subject to this subpart, you must not discharge from the EGU into the atmosphere any gases that

contain CO 2 in excess of the applicable CO 2 emissions standard specified in Table 2 to this subpart. Each CO 2 emissions standard has a minimum of two significant digits.

5. Section 60.4333 is amended by adding paragraph (g) to

read as follows:

**§60.4333 What are my general requirements for complying with this subpart?** 

* * * * * (g) If you own or operate a stationary combustion turbine subject to a CO 2 emissions standard in §60.4325, compliance determinations are to be made on a 12-operating month rolling average, you must determine compliance monthly by calculating the average CO 2 emissions rate for the affected EGU at the end of***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 3422 of 403 each preceding 12-operating month period.

6. Section 60.4373 is added to read as follows:

**§60.4373 How do I monitor and collect data to demonstrate compliance with my CO**  **2 emissions standard using a CO**  **2 CEMS?**  (a) You must prepare a monitoring plan in accordance with the applicable provisions in §§75.53(g) and (h) of this chapter. (b) You must measure the hourly CO 2 mass emissions from each affected EGU using the procedures specified in paragraphs (b)(1) through (5) of this section, except as provided in paragraph (c)

of this section. (1) You must install, certify, operate, maintain, and

calibrate a CO 2 continuous emission monitoring system (CEMS) to directly measure and record CO 2 concentrations in the EGU exhaust gases vented to the atmosphere and an exhaust gas flow rate monitoring system according to §75.10(a)(3)(i) of this chapter.

If CO 2 concentration is measured on a dry basis, you must also install, certify, operate, maintain, and calibrate a continuous moisture monitoring system, according to §75.11(b) of this chapter. (2) For each monitoring system used to determine the CO 2 mass emissions, you must meet the applicable certification and quality assurance procedures in §75.20 of this chapter and appendices B and D to part 75 of this chapter.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 3423 of 403 (3) You must use a laser device to measure each exhaust gas

stack or duct dimensions at the flow monitor and the reference method sampling locations prior to the initial setup (characterization) of the flow monitor. For circular stacks, make three determinations of the diameter and average the results. For rectangular stacks or ducts, make three measurements of each dimension (i.e., depth and width) and average the results. If the flow rate monitor or reference method sampling site is relocated, repeat these measurements at

the new location. (4) Only unadjusted exhaust gas volumetric flow rates can be used to determine the hourly CO 2 mass emissions from the affected EGU; the bias adjustment factors described in Section 7.6.5 of Appendix A to part 75 of this chapter cannot be applied to the exhaust gas flow rate data. (5) If you elect to use Method 2 in Appendix A-1 to this part to perform the required relative accuracy test audits (RATAs) of the part 75 flow rate monitoring system, you must use a calibrated Type-S pitot tube or pitot tube assembly. Use of the default Type-S pitot tube coefficient is not permitted. (c) As an alternative to complying with paragraph (b) of this section, you may determine the hourly CO 2 mass emissions by using Equation G-4 in appendix G to part 75 of this chapter according to the requirements specified in paragraphs (c)(1) and***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 3424 of 403 (2) of this section. (1) You must implement the applicable procedures in appendix D to part 75 of this chapter to determine hourly unit heat input rates (MMBtu/h), based on hourly measurements of fuel flow rate and periodic determinations of the gross calorific value (GCV) of each fuel combusted. (2) You may determine site-specific carbon-based F-factors using Equation F-7b in section 3.3.6 of appendix F to part 75 of this chapter, and you may use these F c values in the emissions calculations instead of using the default F c values in the Equation G-4 nomenclature. (d) You must install, calibrate, maintain, and operate watt meter (and meters) to continuously measure and record the gross electrical output from the affected EGU. If the affected EGU is a CHP EGU, you must also install, calibrate, maintain, and operate meters to continuously determine and record the total useful recovered thermal energy. For steam this information includes flow rate, temperature, and pressure. If the CHP EGU has a direct mechanical drive application, you must submit a plan to the Administrator or delegated authority for approval of how gross energy output will be determined. (e) If two or more affected EGUs serve a common electrical generator, you must apportion the combined hourly gross output to the individual EGUs using a plan approved by the***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 3425 of 403 Administrator (e.g., using steam load or heat input to each affected EGU). (f) In accordance with §60.13(g), if two or more EGUs that implement the continuous emission monitoring provisions in paragraph (b) of this section share a common exhaust gas stack and are subject to the same emissions standard under §60.4325, you may monitor the hourly CO 2 mass emissions at the common stack in lieu of monitoring each EGU separately. If this option is chosen, the hourly gross load (electrical, thermal, and/or mechanical, as applicable) shall be the sum of the hourly loads for the individual EGUs and the operating time shall be expressed as “stack operating hours” (as defined in §72.2 of this chapter). If compliance with the applicable emissions standard in §60.4325 is attained at the common stack, each EGU sharing the stack is considered to be in compliance. (g) In accordance with §60.13(g), if the exhaust gases from an EGU that implements the continuous emission monitoring provisions in paragraph (b) of this section are vented to the atmosphere through multiple stacks (or if the exhaust gases are routed to a common stack through multiple ducts and you elect to monitor in the ducts), you must monitor the hourly CO 2 mass emissions and the “stack operating time” (as defined in §72.2 of this chapter) at each stack or duct separately. In this case, compliance with the applicable emissions standard in §60.4325 is***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 3426 of 403 determined by summing the CO 2 mass emissions measured at the individual stacks or ducts and dividing by the total gross output for the unit.

7. Section 60.4374 is added to read as follows:

**§60.4374 How do I demonstrate compliance with my CO 2**  **emissions**

**standard and determine excess emissions?** (a) You must calculate the CO 2 mass emissions output-based rate for your affected EGU by using the hourly CO 2 mass emissions and total gross output data determined and recorded according to the procedures specified in §60.4373 for each operating hour in the applicable operating month compliance period for the CO 2 emissions standard applicable to the affected EGU, and the calculation procedures specified in paragraphs (a)(1) through (a)(5) of this section. (1) Only operating hours in the operating month compliance period are used for the compliance determination calculation for which quality-assured data are obtained for all parameters used to determine the hourly CO 2 mass emissions. No operating hours in which the substitute data provisions of part 75 of this chapter are used for any of those parameters are to be included in the calculation. For the compliance determination calculation, you must obtain “valid” hourly CO 2 mass emission values for a minimum of 95 percent of the operating hours in the operating month***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 3427 of 403 compliance period for the CO 2 emissions standard applicable to

the affected EGU. (2) Calculate the total CO 2 mass emissions for the affected EGU’s operating month compliance period by summing the hourly CO 2 mass emissions values for the affected EGU determined to be valid according to the conditions specified in paragraph (a)(1) of this section for all of the operating hours in the applicable operating month compliance period. (3) For each operating hour of the operating month compliance period used in paragraph (a)(2) of this section to

calculate the total CO 2 mass emissions, determine the affected EGU’s corresponding hourly gross output according to the procedures specified in paragraphs (a)(3)(i) and (ii) of this section, as appropriate for the type of stationary combustion turbine or steam generating unit used for the EGU. For an operating hour in which there is no gross electrical load, but there is mechanical or useful thermal output, you must still determine the gross output for that hour. (i) The gross output of a stationary combustion turbine with respect to CO 2 emissions is determined as specified in paragraphs (a)(3)(i)(A) and (B) of this section. (A) The gross electrical and mechanical output from the stationary combustion turbine plus 75 percent of the useful thermal output measured relative to ISO conditions that is not***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 3428 of 403 used to generate additional electrical or mechanical output or to enhance the performance of the unit ( e.g. , steam delivered to an industrial process); or (B) For a CHP EGU where at least 20.0 percent of the total gross useful energy output consists of electric or direct mechanical output and 20.0 percent of the total gross useful energy output consists of useful thermal output on an three calendar year rolling average basis, the gross electrical and mechanical output from the stationary combustion turbine facility divided by 0.95 plus 75 percent of the useful thermal output measured relative to ISO conditions that is not used to generate additional electrical or mechanical output or to enhance the performance of the unit (i.e., steam delivered to an industrial process). (ii) Gross output of a steam generating unit with respect

to CO 2 emissions is determined as specified in paragraphs (a)(3)(ii)(A) and (B) of this section. (A) The gross electrical and mechanical output from the steam generating unit minus any electricity used to power the feedwater pumps plus 75 percent of the useful thermal output measured relative to ISO conditions that is not used to generate additional electrical or mechanical output or to enhance the performance of the unit ( e.g. , steam delivered to an industrial process); or***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 3429 of 403 (B) For a CHP EGU where at least 20.0 percent of the total gross useful energy output consists of electric or direct mechanical output and 20.0 percent of the total gross useful energy output consists of useful thermal output on an three calendar year rolling average basis, the difference of gross electrical and mechanical output from the affected steam generating unit minus any electricity used to power the feedwater pumps divided by 0.95 plus 75 percent of the useful thermal output measured relative to ISO conditions that is not used to generate additional electrical or mechanical output or to enhance the performance of the unit (i.e., steam delivered to an industrial process). (4) Calculate the total gross output for the affected EGU’s compliance period by summing the hourly gross output values for the affected EGU determined from paragraph (a)(2) of this section for all of the operating hours in the applicable compliance period. (5) Calculate the CO 2 mass emissions output-based rate for the affected EGU by dividing the total CO 2 mass emissions value from paragraph (a)(2) of this section by the total gross output value from paragraph (a)(4) of this section. (b) If the CO 2 mass emissions output-based rate for the affected EGU determined according to the procedures specified in paragraph (a) of this section is less than or equal to the CO 2***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 3430 of 403 emissions standard in Table 2 of this subpart applicable to the EGU, then the affected EGU is determined to be in compliance with the emissions standard. If the average CO 2 mass emissions rate is greater than the CO 2 emissions standard in Table 2 of this subpart applicable to the EGU, then the affected EGU is

determined to have excess emissions.

8. Section 60.4375 is amended by revising the section heading to read as follows:

**§60.4375 What reports must I submit to comply with my NO x**  **and SO 2**  **emissions limits?**

* * * * *

9. Section 60.4376 is added to read as follows:

**§60.4376 What notifications and reports must I submit to comply with my CO**  **2 emissions standard?** 

(a)(1) You must prepare and submit the notifications specified in §§60.7(a)(1) and (a)(3) and §60.19, as applicable to your affected EGU. (2) You must prepare and submit notifications specified in §75.61 of this chapter, as applicable to your affected EGU. (b) You must prepare and submit reports according to paragraphs (b) through (d) of this section, as applicable. (1) For EGUs that are required, pursuant to §§60.4333 (g),***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 3431 of 403 to conduct initial and on-going compliance determinations on a 12-operating month rolling average basis with respect to the standard in §60.4325 you must submit electronic quarterly reports as follows. After the first 12-operating months have been accumulated for the EGU, a report for the calendar quarter that includes the twelfth operating month shall be submitted no later than 30 days after the end of that quarter. Thereafter, a report for each subsequent calendar quarter shall be submitted, no later than 30 days after the end of the quarter. (2) Each quarterly report shall include the following information, as applicable: (i) Each rolling average CO 2 mass emissions rate for which the last (twelfth) operating month in a 12-operating month compliance period falls within the calendar quarter. Calculate each average CO 2 mass emissions rate according to §§60.4374. Report the dates (month and year) of the first and twelfth operating months in each compliance period for which a CO 2 mass emissions rate calculation is performed. If there are no compliance periods that end in the quarter, include a statement

to that effect; (ii) Identification of each operating month in the calendar quarter with excess CO 2 emissions. If one or more compliance periods end in the quarter; (iii) The percentage of valid CO 2 mass emission rates (as***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 3432 of 403 defined in §60. 4374) in each 12-operating month compliance period described in paragraph (b)(1)(i) of this section (i.e.,

the total number of valid CO 2 mass emission rates in that period divided by the total number of operating hours in that period, multiplied by 100 percent); and (iv) Indication of which compliance option is being

followed under §60.4325. (3) The final quarterly report of each calendar year must contain the following: (i) Gross electric output sold to an electric grid over the 4 quarters of the calendar year; and (ii) The potential electric output of the facility. (c) All electronic reports required under paragraph (b) of this section shall be submitted using the Emissions Collection and Monitoring Plan System (ECMPS) Client Tool provided by the Clean Air Markets Division in the Office of Atmospheric Programs

of the EPA. (d) You must meet all applicable reporting requirements and submit reports as required under subpart G of part 75 of this chapter.

10. Section 60.4390 is amended by revising the section heading to read as follows:

**§60.4390 What records must I maintain to comply with my NO x**  **and*****E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 3433 of 403

**SO 2**  **emissions limits?**

* * * * *

11. Section 60.4391 is added to read as follows:

**§60.4391 What records must I maintain to comply with my CO 2**  **emissions limits?**

(a) You must maintain records of your information used to demonstrate compliance with this subpart as specified in §60.7 (b) and (f). (b) You must follow the applicable recordkeeping requirements and maintain records as required under subpart F of part 75 of this chapter. (c) You must keep records of the calculations performed to

determine the total CO 2 mass emissions for: (1) Each operating month (for all affected units); (2) Each compliance period, including, as applicable, each 12-operating month compliance period. (d) You must keep records of the applicable data recorded and calculations performed used to determine your affected EGU’s gross output for each operating month. (e) You must keep records of the calculations performed to determine the percentage of valid CO 2 mass emission rates in each compliance period. (f) You must keep records of the calculations performed to***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 3434 of 403 assess compliance with each applicable CO 2 mass emissions standard in §60.4325. (g) You must keep records of the calculations performed to determine any site-specific carbon-based F-factors used in the emissions calculations (if applicable). (h)(1) Your records must be in a form suitable and readily available for expeditious review. (2) You must keep each record for 5 years following the date of each occurrence, measurement, maintenance, corrective action, report, or record to demonstrate compliance with a 12- operating month emissions standard. (3) You must keep each record on site for at least 2 years after the date of each occurrence, measurement, maintenance, corrective action, report, or record, according to §60.7. You may keep the records off site and electronically for the remaining year(s) as required by this subpart.

12. Section 60.4395 is amended to read as follows:

**§60.4395 When must I submit my reports?**

Consistent with §60.7(c), all reports required under §60.7(c) must be postmarked by the 30th day following the end of each 6-month period, except as specified in §60.4376

13. Section 60.4421 is added to read as follows:

**§60.4421 What definitions with respect to CO 2**  **emissions apply to*****E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 3435 of 403 **this subpart?**

Base load rating means 100 percent of the manufacturer's design heat input capacity of the combustion turbine engine at ISO conditions using the higher heating value of the fuel (heat input from duct burners is not included). Electric generating unit or EGU means any steam electric generating unit or stationary combustion turbine that generates electricity.

Excess emissions means a specified averaging period over which either (1) the NO X , CO 2 or SO 2 emissions rate are higher than the applicable emissions standard in §60.4320, §60.4325 or §60.4330; (2) the total sulfur content of the fuel being combusted in the affected facility or the SO 2 emissions exceeds the standard specified in §60.4330; or (3) the recorded value of a particular monitored parameter, including ration of water or steam to fuel, is outside the acceptable range specified in the parameter monitoring plan for the affected unit.

Gross useful energy output means: (1) For simple cycle and combined cycle combustion turbines, the gross useful work performed is the gross electrical or direct mechanical output from both the combustion turbine engine and any associated steam turbine(s). (2) For a CHP combustion turbine, the gross useful work***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 3436 of 403 performed is the gross electrical or direct mechanical output from both the combustion turbine engine and any associated steam turbine(s) plus any useful thermal output measured relative to ISO conditions (except for GHG calculations in §60.4374 as only 75 percent credit is given) that is not used to generate additional electrical or mechanical output or to enhance the performance of the unit ( i.e. , steam delivered to an industrial process). Heat recovery steam generating unit (HRSG) means a unit where the hot exhaust gases from the combustion turbine engine are routed in order to extract heat from the gases and generate useful output. Heat recovery steam generating units can be used

with or without duct burners. Integrated gasification combined cycle electric utility steam generating unit (IGCC) means an electric utility steamgenerating unit that burns solid-derived fuels in a combinedcycle combustion turbine plus any integrated equipment that provides electricity or useful thermal output to either the turbine engine and HRSG or to power auxiliary equipment. No solid fuel is directly combusted in the unit during operation. Net-electric output means:***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 3437 of 403 (1) The gross electric sales to the utility power distribution system minus purchased power on a three calendar year rolling average basis; or (2) For combined heat and power facilities where at least 20.0 percent of the total gross useful energy output consists of electric or direct mechanical output and 20.0 percent of the total gross useful energy output consists of useful thermal output on a 3 calendar year rolling average basis, net-electric

output means the gross electric sales to the utility power distribution system minus purchased power of the thermal host facility or facilities on a three calendar year rolling average

basis. Operating month means a calendar month during which any fuel is combusted in the EGU at any time. Potential electric output means 33 percent or the design electric output efficiency on a net output basis times the maximum design heat input capacity (expressed in MMBtu/h) of the steam generating unit, multiplied by 10 6 Btu/MMBtu, divided by 3,413 Btu/KWh, divided by 1,000 kWh/MWh, and multiplied by 8,760 h/yr (e.g., a 35 percent efficient EGU with a 100 MW (341 MMBtu/h) fossil-fuel heat input capacity would have a 306,420 MWh 12 month potential electrical output capacity). Stationary combustion turbine means all equipment, including but not limited to the combustion turbine engine, the fuel, air,***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 3438 of 403 lubrication and exhaust gas systems, control systems, heat recovery system, steam turbine, fuel compressor, heater, and/or pump, post-combustion emission control technology, and any ancillary components and sub-components plus any integrated equipment that provides electricity or useful thermal output to either the boiler or to power auxiliary equipment. Stationary means that the combustion turbine is not self propelled or intended to be propelled while performing its function. It may, however, be mounted on a vehicle for portability. Steam generating unit means any furnace, boiler, or other device used for combusting fuel and producing steam (nuclear steam generators are not included) plus any integrated equipment that provides electricity or useful thermal output to either the boiler or to power auxiliary equipment. System emergency means any abnormal system condition that requires immediate automatic or manual action to prevent or limit loss of transmission facilities or generators that could adversely affect the reliability of the power system.

* * * * *

14. Table 2 is added to read as follows:

Table 2 to Subpart KKKK of Part 60 – EGU CO 2 Emission Standards

**Affected EGU C**  **O 2**  **E mission Standard**  Stationary combustion turbine 450 kilograms (kg) of CO 2 per***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 3439 of 403 that has a design heat input to the turbine engine of greater than 250 MW (850MMBtu/h), that burns fossil fuel for more than 10.0 percent of the average annual heat input during a 3 year rolling average basis, and supplies one-third or more of its potential electric outputand more than 219,000 MWh netelectrical output to a utility distribution system on a 3 year rolling average basis. megawatt-hour (MWh) of gross output (1,000 lb/MWh) on a 12- operating month rolling average

Stationary combustion turbine that has a design heat input to the turbine engine equal to or less than 250 MW (850MMBtu/h), that burns fossil fuel for more than 10.0 percent of the average annual heat input during a 3 year rolling averagebasis, and that supplies onethird or more of its potential electric output and more than 219,000 MWh net-electrical output to a utility distribution system on a 3 year rolling average basis. 500 kg of CO 2 per MWh of gross output (1,100 lb CO 2 /MWh) on a 12-operating month rolling average

15. Table 3 is added to reads as follows:

Table 3 to Subpart KKKK of Part 60 – Applicability of Subpart A General Provisions to EGU CO 2 Emissions Standards in Subpart KKKK

**General Provisions**  **citation Subject of**  **citation Applies to**  **subpart KKKK**  **Explanation**

§60.1 Applicability Yes

§60.2 Definitions Yes Additional terms defined in §60.4420***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 3440 of 403

§60.3 Units and Abbreviations Yes §60.4 Address Yes

§60.5 Determination of construction or modification Yes

§60.6 Review of plans Yes

§60.7 Notification and Recordkeeping Yes Only the requirements to submit the notification in 60.7(a)(1) and (a)(3) §60.8 Performance tests No §60.9 Availability of Information Yes §60.10 State authority Yes

§60.11 Compliance with standards and maintenance requirements No

§60.12 Circumvention Yes

§60.13 Monitoring requirements Yes

§60.14 Modification No §60.15 Reconstruction No §60.16 Priority list No

§60.17 Incorporations by reference Yes

§60.18 General control device requirements No

§60.19 General notification and reporting requirements Yes***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 3441 of 403 **PART 70—[AMENDED]** 16. The authority citation for part 70 continues to read as

follows: **Authority** : 42 U.S.C. 7401 et seq. 17. Section 70.2 is amended by adding new paragraph (4) to

the definition of “ Regulated pollutants (for presumptive fee

calculation )” to read as follows: **§ 70.2 Definitions.**

* * * * * Regulated pollutant (for presumptive fee calculation), which is used only for purposes of § 70.9(b)(2), means any “regulated air pollutant” except the following: (1) Carbon monoxide; (2) Any pollutant that is a regulated air pollutant solely

because it is a Class I or II substance to a standard promulgated under or established by title VI of the Act; or (3) Any pollutant that is a regulated air pollutant solely because it is subject to a standard or regulation under section 112(r) of the Act; (4) Greenhouse gases.

* * * * * 18. Section 70.9 is amended by revising paragraph (b)(2)(i), by adding a new paragraph (b)(2)(v)) to read as

follows:***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 3442 of 403 **§ 70.9 Fee determination and certification.**

* * * * * (b) * * * (2)(i) The Administrator will presume that the fee schedule meets the requirements of paragraph (b)(1) of this section if it

would result in the collection and retention of an amount not less than $25 per year [as adjusted pursuant to the criteria set forth in paragraph (b)(2)(iv) of this section] times the total tons of the actual emissions of each regulated pollutant (for presumptive fee calculation) emitted from part 70 sources and the GHG cost adjustment required under paragraph (b)(2)(v) of

this section.

* * * * * (v) GHG cost adjustment . The amount calculated in paragraph (b)(2)(i) of this section shall be increased by the GHG cost adjustment determined as follows: For each activity identified in the following table, multiply the number of activities performed by the permitting authority by the burden hours per activity, and then calculate a total number of burden hours for all activities. Next, multiply the burden hours by the average cost of staff time, including wages, employee benefits

and overhead.

Activity Burden***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 3443 of 403

hours per activity Preparing a permit application (add GHG to a non-GHG permit) Modification due to GHG Modification to address GHG in a non-GHG permit Address GHG at permit renewal 43 40

9 4

* * * * * **PART 71—[AMENDED]** 19. The authority citation for part 71 continues to read as

follows: **Authority** : 42 U.S.C. 7401 et seq. 20. Section 71.2 is proposed to be amended by adding new paragraph (4) to the definition of “ Regulated pollutant (for fee

calculation )” to read as follows: **§ 71.2 Definitions.**

* * * * * Regulated pollutant (for fee calculation), which is used only for purposes of § 71.9(c), means any “regulated air pollutant” except the following: (1) Carbon monoxide; (2) Any pollutant that is a regulated air pollutant solely

because it is a Class I or II substance to a standard promulgated under or established by title VI of the Act; or***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 3444 of 403 (3) Any pollutant that is a regulated air pollutant solely because it is subject to a standard or regulation under section 112(r) of the Act; (4) Greenhouse gases.

* * * * *

21. Section 71.9 is amended: a. By revising paragraph ©(1), b. By revising paragraph ©(2) c. By adding a new paragraph ©(8).

The additions read as follows: **§ 71.9 Fee determination and certification.**

* * * * * (c) Establishment of fee schedule

. (1) For part 71 programs that are administered by EPA, each part 71 source shall pay an annual fee which is the sum of: (i) $32 per ton (as adjusted pursuant to the criteria set forth in paragraph (n)(1) of this section) times the total tons of the actual emissions of each regulated pollutant (for fee calculation) emitted from the source, including fugitive

emissions; and (ii) any GHG fee adjustment required under paragraph ©(8)

of this section. (2) For part 71 programs that are fully delegated pursuant

to § 71.10:***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 3445 of 403 (i) Where the EPA has not suspended its part 71 fee collection pursuant to paragraph ©(2)(ii) of this section, the annual fee for each part 71 source shall be the sum of: (A) $24 per ton (as adjusted pursuant to the criteria set forth in paragraph (n)(1) of this section) times the total tons of the actual emissions of each regulated pollutant (for fee calculation) emitted from the source, including fugitive

emissions; and (B) any GHG fee 45djusttment required under paragraph (c)(8) of this section. (ii) Where the delegate State collects fees from part 71

sources under State law which are sufficient to fund the delegated part 71 program, the EPA may suspend its collection of part 71 fees. The specific terms and conditions regarding the suspension of fee collection will be addressed in the applicable delegation agreement pursuant to § 71.10.

* * * * * (8) GHG fee adjustment . The annual fee shall be increased by a GHG fee adjustment for any source that has initiated an activity listed in the following table since the fee was last paid. The GHG fee adjustment shall be equal to the set fee provided in the table for each activity that has been initiated since the fee was last paid:***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 3446 of 403 Activity Set fee Preparing a permit application (add GHG to a non-GHG permit) Modification due to GHG Modification to address GHG in a non-GHG permit Address GHG at permit renewal $2,236 $2,080 $468 $208

* * * * *

**PART 98—[AMENDED]**

22. The authority citation for part 98 continues to read as

follows: Authority: 42 U.S.C. 7401-7671q.

**Subpart PP—[AMENDED]**

23. Section 98.426 is amended by adding paragraph (h) to

read as follows: §98.426 Data reporting requirements.

* * * * * (h) If you capture a CO 2 stream from an electricity generating unit that is subject to subpart D of this part and

transfer CO 2 to any facilities that are subject to subpart RR of this part, you must: (1) Report the facility identification number associated with the annual GHG report for the subpart D facility,***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 3447 of 403 (2) Report each facility identification number associated with the annual GHG reports for each subpart RR facility to

which CO 2 is transferred, and (3) Report the annual quantity of CO 2 in metric tons that is transferred to each subpart RR facility. 24. Section 98.427 is amended by adding paragraph (d) to

read as follows: §98.427 Records that must be retained. (d) Facilities subject to §98.426(h) must retain records of CO 2 in metric tons that is transferred to each subpart RR facility.