Chapter 3
Costs and Benefits
Contents
3.1	Costs and Benefits Assessment To Support Proposed Rule	2
3.2	Regulatory Impact Analysis (RIA)	26
3.3	Costs	67
3.3.1 Costs of a New Coal-Fired Unit With Partial CCS vs. One Without CCS	113
3.4	Lack of Benefits	132
3.5	Natural Gas Price Assumptions	147
3.6	Economic Impact Assessment Required by Section 317	155
3.7	Proposed Rule's Effect on Reliability and Affordability of Electricity	158
3.7.1 Proposed Rule Precludes Coal-Fired Generation	215
3.7.2 Coal-Fired Generation Can/Cannot Compete With Gas-Fired Combined Cycle Generation	248
3.7.3 Reliance on Coal Generation	253

Costs and Benefits Assessment To Support Proposed Rule
Insufficient justification based on benefits and costs
 Commenter 10965 states they believe there is insufficient justification for EPA to adopt the Proposed Rules. EPA has not factually demonstrated the benefits of the GHG NSPS and has grossly underestimated its detriments in terms of its imposition of costs on the regulated community and the general public and its negative impacts on the availability of reliable and affordable electricity. Commenter 10091 adds that the Rule would not result in net benefits from avoided negative environmental effects as the environmental impacts of the Rule are negligible and scientifically undetectable. As a consequence, this proposed standards should be withdrawn and not revisited. Commenter 10091 also states the Rule would not result in net benefits from avoided negative health effects as human health is improving  -  partially as a result of climate change.
Commenter 9684 states perhaps to deflect criticism that the administration was waging a war on coal, EPA said the rule would not actually reduce power-sector CO2 emissions and would have no climate change benefits. Natural gas had become so cheap, EPA argued, that few if any new coal plants would be built anyway. The rule would not add costs because it would simply ratify where the market was already going. Commenter asks what was the point is there are no climate change benefits. A recently leaked OMB document about the 2014 version of the rule lets the cat out of the bag. EPA offered this rationale: By statute, in order to issue emission standards for existing sources, the Agency must first propose standards of performance for new sources. The rule's value is instrumental. The point of the Carbon Rule is to position EPA to add costs to existing coal power plants. More precisely, as explained below, the Carbon Rule appears to be the setup for regulating existing coal plants through cap-and-trade.
Commenter 10963 states the proposed standards embody unlawful and unwarranted policies which will only make our nation's electricity supply less diverse, less reliable and more expensive while providing no environmental benefits.
The commenter is not correct that the final standards of performance are without benefits.  It is correct that the base case modeling the EPA performed for this rule projects that, even in the absence of this action, new fossil fuel-fired capacity constructed through 2022 and the years following will most likely be NGCC capacity that complies with the final standards.  This is due to current and projected economic market conditions.  See generally RIA chapter 4. Nonetheless, there could be circumstances where new coal-fired capacity is built  -  commenters to EPA's initial proposal maintained adamantly that this was a possibility (although no specific examples have as yet been provided).  In that event, EPA conducted further analysis which shows that there would potentially be net quantified benefits to society in the form of reduced CO2 emissions and secondary fine PM emissions from SCPC facilities (due to reduced SO2 emissions).  See RIA chapter 5.2.  This analysis does not quantify other benefits of the standard.  The standard provides certainty for new plants (see, for example, the AEP FEED study associated with the Mountaineer project, where the company states that it was abandoning the project due to regulatory uncertainty and the absence of a federal regulatory requirement), and a means to enable carbon control technology that will allow future coal  -  fired capacity in a reduced carbon economy.  See AEP public statement cited in preamble section V.I.4 that CCS represents a potential means of preserving a future for coal: "AEP still believes the advancement of CCS is critical for the sustainability of coal-fired generation." The commenters are also correct as a matter of law that some type of section 111 (b) standard is a legal condition precedent to section 111 (d) guidelines for existing sources, but this rule has positive benefits with or without consideration of that legal consequence. Fossil fuel-fired power plants are the largest domestic source (stationary or mobile) of carbon pollution.  While companies building power plants today are already making cleaner generation choices, such as natural gas combined cycle or coal with CCS, the rule would lock in a lower carbon future and make sure this progress continues.  The plants built under this standard would be cleaner than the average coal unit operating today  -  which emits over 4 million metric tonnes of CO2 a year. By comparison, a new natural gas plant would emit 1.7 million tonnes a year, or about 2.3 million metric tonnes less; and a new, modern coal unit would emit no more than 3 million tonnes per year, or about 1 million tonnes less.
CAA section 111 does not authorize technology-forcing standards unlike section 112
 Commenter 10100 states unlike Section 112 of the CAA, Section 111 is not designed to promote technology-forcing standards. While Congress may have anticipated that some regulated facilities may be unable to meet standards promulgated under Section 112, it did not envision such an outcome for Section 111. Compare Sierra Club v. EPA, 479 F.3d 875, 880-81 (D.C. Cir. 2007) (concluding that Section 112 requires minimum stringency requirements to be based on "the emission level actually achieved by the best performers (those with the lowest emission levels), not the emission level achievable by all sources....") and Natl. Lime Assns v. EPA, 233 F.3d 625, 640 (Dec. 15, 2000), with Lignite Energy Council v. EPA, 198 F.3d 930, 933 (D.C. Cir. 1999) ("new source performance standards set by EPA are not technology-forcing"). Commenter states that although EPA has some latitude in terms of the costs a NSPS may impose, all sources must have the opportunity to satisfy the standards after shouldering the costs. See, e.g., Lignite Energy Council, 198 F.3d 930, 933 (costs cannot be "exorbitant"); Sierra Club v. Costle, 657 F.2d 298, 383 (D.C. Cir. 1981) (upholding costs that were not "excessive" or "unreasonable"); Portland Cement Assn. v. Train, 513 F.2d 506, 508 (D.C. Cir. 1975) (costs cannot be more than the "industry could bear and survive"); Essex Chem. Corp. v. Ruckelshaus, 486 F.2d 427, 433 (D.C. Cir. 1973) (EPA's system cannot be "exorbitantly costly"). Setting standards that affected sources cannot meet is not authorized by Section 111. It also puts EPA in the business of picking fuel source winners and losers, an energy policy authority not granted by Congress to EPA.
Commenter 8925 states EPA and others have argued that the proposed rule is a technology-forcing regulation and will lead to dramatic reductions in control technology costs similar to what we experienced with flue gas desulfurization (FGD) for sulfur and selective catalytic reduction (SCR) for NOx.  However, the EPA NSPS proposal is fundamentally different than those SO2 and NOx regulations. One critical difference is that the SO2 and NOx regulations provided an incentive for pulling the control technology into the market--legally binding caps on emissions.  While there were vigorous debates about the cost of SO2 regulation before it was implemented, and those debates continue to this day, the main disagreement was around cost.   Analysts agreed that control technologies would be deployed.
Commenter 9486 states that  although concern is acknowledged regarding the lack of availability of a natural gas pipeline in Hawaii, the proposal does not recognize that different fuels may ultimately be the best choice for different areas of the U.S. Commenter continues that in this proposal, they believe that U.S. EPA has effectively chosen a single fuel for all new EGUs constructed in the continental U.S. History shows that whenever a technology is given a monopoly of a market, the competitive pressures that previously made the technology economically attractive are removed and the chosen technology becomes much more expensive, and that this is not properly accounted for within U.S. EPA's cost assumptions.
See preamble Sections III.H and V.G. As the D.C. Circuit stated in Lignite Energy Council v. EPA,  "Because it applies only to new sources, we have recognized that section 111 `looks toward what may fairly be projected for the regulated future, rather than the state of the art at present.'Portland Cement Ass'n v. Ruckelshaus, 1486 F.2d 375, 391 (D.C. Cir. 1973)." In addition, "technology-forcing" does not refer to standards which cannot be met, but rather to standards that may be predicated on performance not currently in general use.  In any case, post-combustion CCS is demonstrated at full-scale commercial application.
EGUs as largest emitting sector justifies regulation 
Commenter 9514 adds that indeed, EGUs are "the largest emitting sector," outpacing emissions from all section 202(a) sources combined. Id. at 66,539-40 (section 202(a) sources' emissions are "behind the electricity generating sector"). Therefore, even if the statute did require the Administrator to make a finding that a listed industry contributes significantly to the emission of a particular pollutant that endangers public health or welfare, EPA would amply meet that test here. There is no dispute that fossil fuel-fired EGUs contribute significantly to GHG pollution, which the agency has already determined endangers public health and welfare.
Because CO2 is an air pollutant emitted from a source category EPA has listed for purposes of section 111, EPA may establish standards under section 111 (a) and (b) for CO2 for this source category.  In addition, the EPA issued a final determination that emissions of certain specified GHGs endanger both the public health and the public welfare of current and future generations in the Endangerment and Cause or Contribute Findings for Greenhouse Gases under Section 202(a) of the CAA (74 FR 66,496; Dec. 15, 2009), and has explained in detail how emissions of CO2 from the source category here cause or contribute significantly to the air pollution which endangers.  Indeed, this source category contributes more CO2 than any other domestic source category, as the commenter notes.
Existing regulations are reducing emissions without the necessity of proposed rule
Commenter 10662 states existing regulations are reducing emissions without the necessity of proposed rule, explaining that the nation's coal fleet is already significantly reducing emissions even without consideration of EPA's proposed rule. EPA has increased its regulatory activity in regard to coal in particular, having recently promulgated restrictive rules designed to achieve emissions reductions. At the national level, EPA has imposed strict emissions limitations on other pollutants, including a short timetable for compliance (e.g., the Mercury Air Toxics standards). Existing coal-fired units must either modify existing facilities or take out of service those units made prohibitively expensive by these limitations. These factors are expected to also result in CO2 emissions reductions. West Virginia specifically has already achieved the Administration's goal of reducing CO2 emissions from coal-fired plants by 17 percent between 2005 and 2013. Based on available data, including expected plant closures due to increased regulation, West Virginia projects a 21 percent decrease in CO2 emissions from 2005 levels by 2020 under the existing regulatory framework. The existing regulations are already swiftly moving the coal fleet towards the Administration's and EPA's stated goals of reduction of CO2 emissions, with significant adverse impact on production from coal-fired units. Accordingly, the proposed rule is redundant and arbitrary, particularly considering the additional exorbitant economic and social costs which will result from adoption of the proposal. 
 While existing regulations will lead to significant reductions in hazardous air pollutants and criteria pollutants, they will not necessarily result in substantial GHG reductions. The commenter suggests that because these rules may result in certain plants closing and being replaced with new generating capacity which emit less GHGs, EPA should take no further action.  This comment does not speak to the legal requirement that new sources meet standards reflecting performance of the best system of emission reduction adequately demonstrated.  While companies building power plants today are already making cleaner generation choices as a result of current economic conditions, the proposed rule would lock in a lower carbon future by requiring plants to reduce GHG emissions to the level required by section 111 (a).  As explained in preamble Section V.P, this level is not the business-as-usual level achieved by SCPC. The plants built under this standard would be cleaner than the average coal unit operating today  -  which emits over 4 million metric tonnes of CO2 a year. See preamble Section V.K.  By comparison, a new natural gas plant would emit 1.7 million tonnes a year, or about 2.3 million metric tonnes less; and a new, modern coal unit would emit no more than 3 million tonnes per year, or about 1 million tonnes less.
Consider all six purposes identified in the Costle case
Commenter 9780 states assuming for the sake of argument that the "purposes" identified in the Costle case are relevant to all CAA section 111 rulemakings, then EPA should consider all six purposes cited in the decision.  Commenter notes that EPA cites four of the six purposes.  Commenter explains the fourth purpose is: "The standards must maximize the potential for long-term economic growth by reducing emissions as much as practicable" (emphasis added), and the court explains this purpose reflects a goal to "increase the amount of industrial growth possible within the limits set by the air quality standards." (657 F.2d at 325) Commenter states that by focusing purely on one part of this statutory purpose (to maximize emissions reductions) while ignoring the other component (to maximize long-term economic growth), the Proposal distorts both legislative history and Costle. Commenter adds that "maximizing the use of locally available fuels" 657 F.2d at 339 should be considered in determining BSER and states that EPA acknowledges that partial CCS could not be implemented in many parts of the country, and that EPA arguably violates this statutory purpose.
 
The court was quoting general propositions on which the parties agreed in considering whether section 111 (a) authorizes a variable standard.  The court was not stating the legal requisites for establishing standards under section 111 (a).  Rather, the underlying statutory purposes about which there was evident consensus in the Sierra Club case serves to inform consideration of the enumerated statutory decision factors.  Those factors are discussed at preamble section III.H and V.G.
Commenter 10396 states this proposal goes against prior court decisions. In Sierra Club v. Costle, it was determined that New Source Performance Standards "must not give a competitive advantage to one state over another in attracting industry." The EPA is requiring all coal units built in the future install CCS technologies. This requirement assumes that states will have the opportunity to sell captured CO2 for enhanced oil recovery to offset the costs of CCS. This assumption is not correct. As a "hold-harmless" clause, the EPA states that in instances where a utility does not have the opportunity to sell CO2 to offset costs, they may simply build Natural Gas Combined Cycle (NGCC) plants. The consequences and limitations of this either-or alternative (either CCS or NGCC) have not been thoroughly examined or justified.
The commenters are mistaken. The final standard first of all requires new coal-fired sources to meet an emission limit and does not specify how. Second, EPA explains in the preamble to the final rule that there are multiple compliance pathways for coal-fired sources available, some of which do not involve sequestration.
Commenter 2658 states EPA should work cooperatively to ensure all of its GHG regulations are cost-effective, attainable, and avoid harm to American jobs and the economy.
EPA indicates in section V. of the preamble to the final rule that the standards of performance for new coal-fired steam electric generating units are technically feasible at reasonable cost and are otherwise adequately demonstrated.  However, the EPA further projects that the impacts, including economic impacts, of the standard may be minimal because even in the absence of the regulation, new generating capacity built through the period of analysis would be in compliance with the standard even in the absence of the regulation.  RIA chapter 4. 
Peer review 
 Commenters 10036, 0585, and 10036 state there is no evidence that the cost estimates and analyses in the proposed rule have undergone a formal peer review, as required by the Data Quality Act <4 The Data Quality Act was enacted through Section 515 of the Consolidated Appropriations Act of 2001, Public Law 106-554. It is sometimes cited as the "Information Quality Act."> and OMB regulations. Commenters urged EPA to undertake a thorough analysis of the costs and benefits of regulation and ensure that the cost-benefit analysis is peer-reviewed and adequate time is afforded the public for consideration and public comment on the environmental and the cost-benefit analysis.
Commenters 10036 and 7977 state that the NETL reports cited by EPA as underpinning EPA's judgments on the cost of partial CCS, as well as EPA's analyses based on the NETL reports, are "highly influential scientific assessments." Although EPA has reportedly assured its Science Advisory Board (SAB) that "the NETL studies were all peer reviewed under DOE peer review protocols and that EPA did not actually conduct additional peer review(s),"< Memorandum: Revised Recommendations on the Adequacy of the Science Supporting the Standards of Performance for Greenhouse Gas Emissions from New Stationary Sources: Electric Utility Generation Units (2060AQ -91) listed in the Spring 2013 Regulatory Agenda, From J. Mihelcic, Chair, SAB Work Group on EPA Planned Actions for SAB Consideration of the Underlying Science, To Members of the Chartered SAB and SAB Liaisons, January 7, 2014>. EPA has provided no evidence of these DOE peer reviews in the proposed rule, and offered no determination as to whether these reviews meet the requirements of OMB's guidelines. As a result, EPA has acted in an arbitrary and capricious manner and abused its discretion by not using peer reviewed sources for its cost and performance analysis. Commenter continues (7977) the Cabinet notes that the Notice of Data Availability (NODA) and Technical Support Documents (TSD), included in the Docket at EPA-HQ-OAR-2013-0495 on February 6, 2014, raise significant new issues, discuss subsequent Agency interpretations, and rely upon "additional evidence" not included in the docket when the rule was promulgated. To provide for adequate comment on the actual basis of the determinations in the proposed rule, this conflict must be resolved consistently with the President's directive that the Agency "(vi) work with the Department of Energy and other Federal and State agencies to promote the reliable and affordable provision of electric power through the continued development and deployment of cleaner technologies and by increasing energy efficiency [...]." 78 FR 39535. Given the importance of these reports to EPA's findings on the cost of CCS, the importance of cost in EPA's determination of BSER, and commenter's concerns regarding the cost comparisons made by EPA, as discussed above, they believe that it is incumbent on EPA to make a full showing of the adequacy of the peer review of documents and analyses used in formulating the proposed rule.
 Regarding the Data Quality Act, see response to comments in 2.4 of this RTC.  As shown there, these comments lack both a legal basis and significantly misstate material facts. 
Natural gas demand increasing
Commenter 9678 states even absent this proposed rule, analysts predict increased reliance on natural gas within the electric power sector as older, less-efficient generating facilities are retired from the system. (see Figure 1 from EIA's AEO series included in comment.) Commenter states further that contrary to the AEO 2008 projected steady decline in natural gas use by the electric power sector, AEO 2014 projects an 81 percent increase in natural gas utilization in the electric sector from 2011 to 2040, up from a projected 56 percent increase in AEO 2013, and commenter attributes shift, in part, to the abundant and affordable supplies of natural gas. Commenter 2658 worries that if EPA's projections prove wrong, the rule's cost would skyrocket because it would have prevented the construction of economical new coal-fired power plants. Commenter continues that the broader business community is increasingly concerned about the potentially enormous harm from these rules, and EPA should work cooperatively to ensure all of its GHG regulations are cost-effective, attainable, and avoid harm to American jobs and the economy.
Commenter 8925 states removing either conventional coal or coal with CCS from our US portfolio based in large part on forecasts of future natural gas prices does not seem to appropriately give credence to our historic inability to forecast gas markets nor to serve as a prudent assumption looking forward.
Commenter 8501 states that the proposed GHG NSPS would impose no additional cost also ignores a critical impact of increased natural gas usage for baseload electricity generation. 
 
The EPA's modeling, conducted using the Integrated Planning Model (IPM), as well as modeling conducted by the U.S. Energy Information Administration (EIA), showed that new generating capacity built through the period of analysis would be in compliance with the standard in the baseline scenario, and as a result, there would be no change in behavior as a result of the standard. This finding held true even under a number of alternative scenarios. As a result, the EPA projected there would be negligible costs, benefits, or energy impacts (including changes to natural gas prices) associated with the rule in the period of analysis. In addition, the Regulatory Impact Analysis for the rule includes several illustrative analyses, examining the costs of the rule under a range of natural gas prices and the cost associated with building a coal plant with CCS. (See Chapter 5 of the RIA.) It is important to note that the rule is not a ban on new coal capacity. It simply requires that all new fossil fuel fired power plants emit CO2 at a level reflective of performance of the best system of emission reduction adequately demonstrated.
Reliance on natural gas
Commenter 9780 states EPA's analysis concludes that new conventional coal-fired units are not currently cost competitive with new NGCC units and are unlikely to be so through 2020, so very few are projected to be built. Commenter continues that EPA uses this conclusion to help justify the proposed partial CCS standard, which effectively precludes the building of new coal-based units. Commenter continues that the proposed CO2 standards effectively ensure that the nation becomes more reliant on natural gas-fired power regardless of the future deliverability and cost of natural gas as a generation fuel.
Commenter 8743 states that the fact that natural gas can be used for generating electricity at the present time (in place of technologies requiring use of CCS) does not justify dictating the sole use of natural gas across such geographical areas by regulation. To imply that Congress would condone such decision making in the case where no ambient air quality standard or distinct air quality related value is at stake misconstrues their past rulemaking initiatives.
Commenter 10869 states that although there is a predicted decline in CO2 emissions which is encouraging, commenter emphasizes that a wholesale shift from coal to natural gas in electric power generation will be insufficient to meet the climate challenge. Commenter recently released a report, Gas Ceiling: Assessing the Climate Risks of an Overreliance on Natural Gas for Electricity which found that a transition from a coal- to a natural-gas-dominated electricity system would not be sufficient to meet U.S. climate goals. In addition to heat trapping emissions from combustion, the report also shows how the extraction and transport of natural gas releases even more potent greenhouse gases, and the magnitude of this leakage is not well understood. An electricity system centered on natural gas would also carry significant economic, environmental, and public health risks. Hydraulic fracturing has several environmental and health risks and also requires large quantities of water. Volatile prices, potential shortages during cold snaps, uncertainties in the size of available natural gas supplies combined with growing demand, and the potential for growth in natural gas exports, can all contribute to adverse economic impacts for consumers. Commenter adds that the amount of new non-hydro renewable energy sources, like wind and solar energy, has increased dramatically in recent years as costs continue to fall.
The final standard of performance can be met a variety of ways, not all of which involve CO2 sequestration, so the final standard of performance is not geographically constraining.  The standard, predicated on partial CCS as part of the BSER, does not preclude new coal capacity.  See also preamble section V.I.4.
Natural gas not available in all U.S. locations
 Commenter 9592 states natural gas is not available in all locations in the continental United States. 

Commenters 9396 and 9423 add that EPA's proposal does not appropriately compare electricity generation resource costs and availability, explaining that EPA does not account for the role that a diversified fuel mix plays in assuring a reliable, economically critical electricity generation resource which delivers benefits to society.  EPA claims that natural gas is currently in wide use throughout the country. However, "in wide use" is not the equivalent of available. There are many areas of the continental U.S. which lack access to natural gas pipelines, natural gas storage, or necessary infrastructure for building new natural gas plants. Even in areas where natural gas is available, constraints in delivery can impede reliability and have direct economic and safety impacts during periods of high electricity or natural gas demand. Commenter adds that at the same time, new base load and intermediate load plants need to be sited where sufficient electric transmission lines are or can be located. There is no evidence that EPA has conducted the necessary evaluations of the cost or availability of the critical infrastructure necessary to designate natural gas as available throughout the continental U.S. in order the meet the statutory requirements of Section 111 NSPS rulemaking. In the case where utilities locate new gas plants, long natural gas transmission lines will need to be constructed to these plants, and the impacts of this activity have not been evaluated by EPA.

Commenter 9396 continues that in asserting NGCC as the 'default' baseload generation resource, EPA has not recognized the limitations to the availability of natural gas in all locations of the U.S. EPA relies upon its IPM modeling to argue that because of low natural gas prices and other market conditions, almost no coal capacity (only 1.5 GW with CCS) will be built until 2020 that is not already permitted or will include CCS. However, such modeling does not appear to account for areas of the country, including areas where some afford members supply electricity, which either lack access to natural gas pipeline and delivery infrastructure46 or have no spare capacity with which to supply additional gas. In such areas, even if it would be economically advantageous to build a NGCC facility, it would not be possible without costly build-out of natural gas infrastructure. In addition, there are areas where constructing a NGCC plant is possible due to access to natural gas because it is near sufficient natural gas infrastructure, but construction of very long electrical transmission lines back to the utility's service territory make the project uneconomical. Commenter sums that increased reliance on natural gas for electricity generation will require substantial infrastructure investment and states that according to the MIT Energy Initiative, $210 billion in natural gas infrastructure investment will be required over the next 20 years to supply growing gas demand. Further increasing natural gas demand through replacement of coal-fueled generation can reasonably be expected to require even greater infrastructure investment.

Commenter 10022 states that access to fuel resources is limited and varies from location to location, explaining that methods employed for power generation vary widely throughout Alaska according to regionally available resources. Natural gas is available for urban Anchorage and its neighboring utilities, but otherwise is not available to most utilities elsewhere in Alaska. Renewable power opportunities also vary from location to location. Significant accomplishments have been made in recent years to displace fossil fuel use with renewable energy infrastructure; however, the generation and transmission infrastructure throughout the state is still very limited. Commenter posits that the GHG NSPS discriminates against communities that do not have access to natural gas, and in those communities, businesses will not be able to afford to operate, families will be displaced and community's financial health will deteriorate. Commenter (10022) continues, stating unlike interconnected utilities in the contiguous US, Alaska utilities do not have the option of relying on an integrated grid system for backup support and closes stating that the cost of partial CCS will be exorbitant and cannot be supported by our limited population.

Commenter 8501 states the proposed rule contradicts President Obama's intentions to diversify energy development in the US by channeling new electric power production towards natural gas, at the expense of new technology development in coal resources (over 80% of Indiana's electricity generation is fueled by coal).

Commenters 7893 and 10504 state generation and transmission infrastructure throughout Alaska is still very limited. The GHG NSPS disregards the needs of communities without access to natural gas. In those communities, businesses will not be able to afford to operate, families will continue to be displaced, and communities' financial security will continue to deteriorate.
Commenter 9407 states natural gas pipeline infrastructure may not be sufficient to transport natural gas needed for electric generation. EPA does not include a reasoned analysis of natural gas availability and pricing and this deficiency that makes this proposal arbitrary and capricious.

Commenter 9407 states that natural gas pipeline infrastructure may not be sufficient to transport natural gas needed for electric generation. Considering the importance this proposal places on of the need for natural gas availability, based on this rulemaking's record, EPA has appears to have performed limited analysis actually examining issues surrounding natural gas transportation capabilities to electric generating facilities that must be strategically located throughout the nation to support electric grid reliability. EPA appears to base availability assumptions on available natural gas reserves coupled with recent low prices. While natural gas may be available at gas transmission hubs, its availability on needed generation sites is fundamental in determining whether its rational to promulgate a rule that leaves natural gas as the only practical choice for future fossil-fuel baseload generation. As stated previously, we do not dispute that significantly more natural gas is being utilized for electric generation than the recent past and that this trend is likely to continue. What is at issue here is whether this fuel is certain to be available at sites where new baseload generation may be needed to replace retiring existing coal-fired units or at new sites where new baseload generation is required for additional reliability purposes. Such certainty is fundamental to this proposal rationality.

Commenter 9596 noted with respect to the potential for EGU fuel switching that certain areas of the country, including parts of South Carolina where the commenter operates facilities, are far from existing natural gas pipelines, and would require siting and construction of additional natural gas pipelines to convert the current coal-fired fleet to a fleet that relies on natural gas as its primary fuel.  Commenter 10952 provided a map illustrating that there are vast electric cooperative rural service areas where natural gas supply via pipeline is literally hundreds of miles away from where additional electric generation maybe required.  

Commenter 10662 notes that it is extremely shortsighted of EPA to effectively ban new coal-fired power generation, effectively requiring all new power plants to be natural gas-fired when the existing natural gas pipeline system is inadequate to handle the current peak natural gas demand.  Commenter noted that both construction of expanded gas pipeline capacity and non-pipeline physical infrastructure, including compression, looping, and pipe expansion, would be needed to accommodate the increased natural gas demand. Commenters 9780 and 9600 also noted the need for upgraded natural gas pipeline infrastructure to supply natural gas on a "firm" basis to EGUs.  

Commenter 8501 noted that unlike coal, which can be transported by rail, barge, conveyor, or truck, natural gas can be transported to generating facilities only by pipeline, and that there is a deficiency in pipeline capacity to supply natural gas to sources that would need to use the fuel to generate electricity. Commenter 8501 cited a study that estimated that natural gas pipeline operators will need to invest up to $3 billion in pipeline upgrades to be able to provide enough fuel for the projected additional natural gas fired electric generating facilities- including as many as 6 new natural gas pipelines.

Commenters 9407 and 10952 stated that the existing natural gas pipeline infrastructure may not be sufficient to transport natural gas needed for electric generation. Commenters 9407, 10097, and 10952  asserted that EPA has apparently spent little effort actually examining issues surrounding natural gas transportation capabilities to electric generating facilities that must be strategically located throughout the nation to support electric grid reliability. Commenter 10952 stated that the issue related to the existing natural gas pipeline infrastructure is whether natural gas is certain to be available at sites where new baseload generation may be needed to replace retiring coal-fired units or at new sites where new base load generation is required for additional reliability purposes. Such certainty is fundamental to this proposal rationality.

Commenter 9407 cited two recent studies that address additional needs for natural gas pipeline infrastructure to meet increasing market demands. The studies found that a significant amount of mainline and lateral miles of new pipelines to power plant sites would need to be constructed.  The commenter noted that while additional natural gas pipelines will be necessary to sustain grid reliability and provide electric service to consumers at a reasonable cost, EPA has provided no information in connection this rulemaking to show that it has evaluated needed additional natural gas supply capacity as a result of this rulemaking. EPA has either ignored these natural gas availability and pricing questions or has failed to realize that any reasonable evaluation this proposed rule must include them. EPA's failure to include a reasoned analysis of the need for additional natural gas pipeline infrastructure is yet another deficiency that makes this proposal arbitrary and capricious.

Commenter 9396 states that in asserting NGCC as the 'default' base load generation resource, EPA has not recognized the limitations to the availability of natural gas in all locations of the U.S., and states that EPA's modeling does not appear to account for areas of the country, including areas where Commenter 9396's members supply electricity, either that lack access to natural gas pipeline and delivery infrastructure or that lack spare capacity with which to supply additional gas.  Commenter 9396 asserts that in such areas, even if it would be economically advantageous to build a NGCC facility, it would not be possible without costly build-out of natural gas infrastructure.  Commenter 10039 notes that US DOE NETL Cost and Performance Baseline modeling relied on by EPA assumes that natural gas transportation infrastructure is adequate to accommodate all new NGCC units even though US DOE is aware that additional natural gas pipeline infrastructure will be needed for expanded use of natural gas for electric generation. 

Commenter 9396 also notes that there are also areas where constructing a NGCC plant is possible due to access to natural gas because it is near sufficient natural gas infrastructure, but  where the needed construction of very long electrical transmission lines back to the utility's service territory would make the project uneconomical.

Commenter 10098 stated that retrofitting technology to existing EGUs or a requirement for existing EGUs to switch to new sources of fuel will be much more costly than applying the technology to new and modified sources. Commenter 10098 noted that an existing facility utilizing coal may not even have access to natural gas pipelines in certain regions of the country, or may be dedicated to a specific fuel source due to transportation infrastructure or design limitations, and that unlike new facilities that can make siting and fuel source decisions in response to existing regulations and markets, existing sources made these initial decisions without any indication that EPA would regulate GHG emissions and will face burdensome and costly actions were they now required to comply with NSPS standards for greenhouse gas  emissions.

Commenter 9734 stated that it is simply not feasible for the nation's entire existing coal-fired generating capacity to be transitioned to natural gas, as natural gas generation requires transportation from natural gas wells to power plants via an intricate network of interstate pipelines and compressor stations that allow the gas to be constantly pressurized. Commenter 9734 concluded that these requirements raise not only infrastructure concerns but also safety and national security concerns, including the potential for sabotage of the natural gas pipeline network. 
EPA does not agree with these concerns. The natural gas infrastructure issues are entirely manageable under this rule. Natural gas pipeline capacity has historically expanded to meet the needs of new natural gas generation capacity, and the same developments will happen in the future. This is particularly true in the case of comments where additional capacity will be required to meet the requirements of generation already connected to the pipeline system.  It is also true for areas not yet connected to the natural gas pipeline system. Thus, the normal expansion process will address most cases where additional infrastructure is needed.  It is also important to recognize that other areas that are not connected to the pipeline network are connected to the electric transmission network and can receive electricity generated by natural gas; where necessary, the electricity transmission system, like the natural gas pipeline system, has historically expanded to fill the needs of new load as well as new generation.  In the near term, there should be few additional infrastructure needs, as this rule does not affect the continued operation of any existing sources.  In the longer term, as the generating fleet turns over, much of the existing fossil generating will remain and continue to be diverse, while the normal infrastructure development noted above can accommodate much of the new demand.  Moreover, much of the new demand need not be met by natural gas, but by various forms of new renewable energy. The new sources are becoming more competitive and are already serving significant load previously served by older generation sources. Many studies demonstrate the ability for these sources to serve as much as 30 percent of the total load in the U.S.
Promulgate standards for which location is not an unreasonable obstacle
Commenter 9780 states the EPA-cited sections of the 1970 Senate Committee Report to make the point that Congress intended all major new sources to meet the uniform performance standards regardless of their location. 79 Fed. Reg. at 1466 (citing S. Rep. 91-1116 at 16 (1970)), but this legislative history also supports the proposition that EPA should promulgate section 111 standards for which location is not an unreasonable obstacle to compliance.
See preamble Section V.M and other comment responses in RTC 6.
EPA should not expand GHG NSPS to other source categories
Commenters 9401 and 9594 states that EPA should not expand GHG NSPS to other source categories.  Commenter explains that the forging industry is very concerned that when EPA continues its regulatory path towards existing power plants and other industrial sources, it will next turn to natural gas and energy-intensive industries like steel and forging. EPA has also indicated that it is considering GHG new source performance standards for other source categories. Commenter strongly urges the agency not to propose GHG standards of performance for other source categories for the reasons identified below, explaining that first, the regulation of GHG emissions from other source categories in the manufacturing sector would require a fundamentally different approach than for power generation facilities. Manufacturers are impacted by a much broader range of factors- economic conditions vary from industry to industry, for example, and transportation systems, ownership structures, foreign competition, profit margins, and customer bases all vary widely, and, as a consequence, attempting to regulate GHG emissions in the manufacturing sector through one-size-fits-all new source performance standards would be particularly inefficient and costly.  Commenter continues that because most manufacturers face global competition that would not be burdened with the high compliance costs that would result from an EPA-imposed GHG regulation, the resulting imbalance would undoubtedly cause significant job losses in the U.S. without actually reducing GHG emissions.
Commenter 9401 states the precedent nature of the proposed regulation and the use of new source performance standards for source categories on the industrial sector is very problematic for our ability to compete globally, invest in the U.S., and create jobs. Generation of electricity is a relatively simple and uniform technology as compared to the thousands of manufacturing processes that are employed by the industrial sector. Imposing this precedent upon the manufacturing sector will stop the manufacturing progress and stop the re-shoring of manufacturing jobs. Commenter continues the proposed rule, sets a precedent for future regulation on manufacturing that will be impossible to meet. In manufacturing, each source category and each facility within a source category is unique in its design, process, raw materials, accessibility to various fuels, operating flexibilities, and the products it produces. The imposition of this form of regulation has not been imposed upon any of our competitors anywhere in the world, and would put us at a significant competitive disadvantage. Commenter 9401 continues, urging the EPA to incorporate the following elements into the rulemaking. First, provide a stop-gap provision which will ensure that the rule does not set precedent for the industrial sector. The EPA must not set precedent for the EITE industries under this rule because, when applied to manufacturing, it will raise costs and shift jobs and GHG leakage to offshore countries. Commenter 9401 continues that a thorough cost-benefit analysis should be performed, accounting for the impacts of GHG leakage by EITE industries, cost of regulation on business, employment, and households. Commenter adds (9401) that the industrial sector is the only U.S. sector whose CO2 emissions are below 1973 levels, which begs the question, why impose GHG regulations on the manufacturing sector Specifically, the industrial sector's CO2 emissions are 22.4 percent below 1973, while emissions in the other sectors are respectively: Electric, +58.5 percent; transportation, +38.1 percent; residential, +16.4 percent; and commercial, +54 percent.
Commenter 3236 states that increases in other energy prices, fertilizer and machinery will hold negative consequences for agriculture and the manufacturing industry while at the same time making U.S. farmers and ranchers less competitive internationally.  
Newly constructed electricity generating units are the subject of this rulemaking. Comments regarding the regulation of other sectors are outside the scope of this rulemaking.
Exemption for units subject to CAA Section 129 solid waste combustion standards
Commenter 9509 commends EPA for exempting large municipal waste combustors subject to the Subpart Eb from regulation as an EGU under Subpart TTTT, but adds that the proposal must clarify that all municipal waste combustors subject to Section 129 standards are exempt from regulation under the 111(b) EGU standards (regardless of whether EPA chooses to regulate electric utility steam generating units under the newly proposed Subpart Da Alternative (60.46Da) or Subpart TTTT). Commenter continues that this exemption should include the small municipal waste combustors subject to Subpart AAAA, and commenter urges EPA to retain the Section 129 solid waste combustion exemption for municipal waste combustors and extend it to all municipal waste combustors, including those subject to subpart AAAA, adding they believe the same CAA Section 129 exemption must carry over to the proposed 111(d) standards for EGUs. 
The final 111(b) standards only affect fossil fuel-fired EGUs. The EPA explains very specifically the applicability criteria and which units are affected sources under the final rule in preamble section III.C ("Affected Sources") and provides additional detail on other units that are not covered by the final standards in preamble section III.D ("Units Not Covered by this Final Rule").
Nuclear plant closures impact progress achieving climate change goals
Commenter 9406 states EPA should keep in mind the significant value of the nation's nuclear fleet (only carbon free source of predictable, non-intermittent and reliable electric generation and nuclear plants operate at a higher capacity factor than any other generation resource), adding that if current policies are not changed, retirements of nuclear units will have drastic impacts on climate change goals. Commenter states if we continue on the same pace of retirements that we have seen in 2013, we will lose 25% of the nation's nuclear fleet by 2020 and will lose half of the progress the electric industry made to date on the President's climate goal. Subcategory 125 - Design new EGUs to accommodate full CCS under future reduced system costs and a future SCC
Commenter 3594 states the standards as proposed only consider the BSER under current considerations, using current assumptions about CCS costs and the social cost of carbon.  Given the added expense of retrofitting plants not designed for CCS, however, prudence requires that new plants not be built without consideration of changes that can reasonably be expected within their expected life.  All new EGUs must, at the minimum, be designed to accommodate full CCS under future reduced system costs and a future social cost of carbon that will be higher, possible much higher, depending on developing science as well as international frameworks.
Newly constructed electricity generating units are the subject of this rulemaking. Comments regarding existing generation or retrofit of existing sources with CCS is outside the scope of this rulemaking.
The standard does not encourage technology development
Commenter 10552 cites EPA as stating that one of the tests of an acceptable NSPS is its ability to encourage deployment of improved technology. The agency argues that requiring CCS on coal units will encourage its use. This argument is incorrect because power plant developers are free to choose to construct a natural gas-fueled power plant, without CCS. Adding CCS to a coal unit increases the cost differential between coal and gas fueled units, which discourages the use of CCS technology. By creating a regulatory environment in which coal can anticipate no business opportunities for decades, EPA will sharply reduce private sector interest in development of improved CCS technologies.
Commenter 10963 states the proposal will leave the nation's electricity supply less diverse, less reliable and more expensive: EPA's proposal effectively bars the construction of new higher efficiency coal base load power plants that are needed to maintain a diverse, reliable and affordable electricity supply. The centrality of coal based electricity to the reliability and affordability of the nation's electricity supply is beyond dispute. Over the past ten years, coal based electricity generation has supplied more than 45 percent of the nation's electricity supply. Currently, 25 percent of the nation's base load power generation capacity (coal, natural gas and nuclear) is 40 year or older and in another decade that will reach almost 50 percent. The Department of Energy's Energy Information Administration forecasts that 60,000 megawatts of coal based load power capacity will close over the next several years principally in response to EPA's recent mercury and air toxic regulations. To maintain a diverse, reliable and affordable electricity grid, new higher efficiency coal units will be required to replace the retiring older coal, natural gas and nuclear electricity generation plants. The importance of supply diversity to the reliability and affordability of electricity is readily apparent. Phillip Moeller, Commissioner, Federal Energy Regulatory Commission (FERC), recently testified that "the power grid is now already at the limit" and the "nation's bulk power system is in a more precarious situation than [he] had feared in years past." Michael Kormos, PJM Interconnection, recently advised FERC that "because less expensive coal generation is retiring and being replaced by other potential high energy cost resources, energy prices could become more volatile due to the increasing reliance on natural gas for electricity generation." Indeed, natural gas prices have more than doubled since their low of$1.82 mm/BTU in April of2012. This past winter, natural gas prices in some regions reached record highs with mid-points around $40 mm/BTU and bids as high as $100 mm/BTU. Daily average power pricing followed swinging wildly from $40 to $800 MWh. In this regard, EPA's analysis and assumptions for electricity and natural gas pricing are inadequate and unrealistic. EPA does not consider the probability of significant price increases. Turning a blind eye toward the inevitable is irresponsible and a costly gamble with the nation's energy future. Coal serves primarily the power generation market, while natural gas serves many needs including power generation, residential heating, commercial feedstock for manufacturers, transportation and, in the near future, the liquefied natural gas export market. EPA's NSPS policies will have a profound effect upon not only the domestic electricity markets but also many sectors of our economy that rely upon natural gas. As the Department of Energy's National Energy Technology Laboratory (NETL) has warned "policies that encourage the use of natural gas to substitute for coal in power generation could very well lead to spectacular price increases for households and industry." Indeed, according to NETL, coal-based electricity restrained the price of electricity and prevented the price of natural gas from matching the rise in the price of oil. EPA's NSPS proposal will change all of that-and for the worse. Nothing in EPA's proposal demonstrates that the agency has performed a reasonable assessment of the impacts of this rule upon the vast number of economic sectors that rely upon reliable and competitively priced electricity and natural gas.
See preamble Sections V.I.4 and V.L, as well as responses on the same issue in RTC 6.
Limited R&D funding hinders CCS cost reduction
Commenter 10036 states in the absence of adequate public participation in funding for research, development, and demonstration (RD&D) facilities, the NETL projected cost reductions have little meaning, that Federal funding for R&D is declining, and that there has been no new federal funding for CCS demonstration projects since enactment of the 2009 American Recovery and Reinvestment Act. 
This comment is beyond the scope of this proceeding. See preamble Sections V.H and V.I for the agency's cost analysis.  See also preamble section V.L. documenting the spurt of technology development following promulgation of the 1971 NSPS based on performance of the then-nascent scrubber technology.
Question if NSPS could prevent construction of new coal-fired power plants in some U.S. regions
Commenter 9195 asks whether in some regions of the United States, the proposed NSPS prevent the construction of new coal-fired power plants or make the construction of such plants absurdly expensive.
Commenter 9486 states U.S. EPA has prescribed a pathway for coal-fired EGUs that is cost prohibitive to implement and in which the net effect does not reduce CO2 emission by the 40% that U.S. EPA is seeking and has used to substantiate its proposal.
Commenter 9191 states the proposal appears to have been crafted with an eye toward implementing President Obama's original position -- that electric utilities remain free to construct new coal-fired power plants but it will bankrupt them.
Commenter 10135 states EPA's proposed rules regarding new fossil-fired and IGCC plants essentially creates an extremely high and prohibitively expensive barrier to new fossil fuel plant development in the near term. 
The EPA's modeling, conducted using the Integrated Planning Model (IPM), as well as modeling conducted by the U.S. Energy Information Administration (EIA), showed that new generating capacity built through the period of analysis would be in compliance with the standard even in the baseline scenario, and as a result, there would be no change in behavior as a result of the standard. This finding held true even under a number of alternative scenarios. As a result, the EPA projected there would be negligible costs, benefits, or energy impacts (including changes to natural gas prices) associated with the rule in the period of analysis. In addition, the Regulatory Impact Analysis for the rule includes several illustrative analyses, examining the costs of the rule under a range of natural gas prices and the cost associated with building a coal plant with CCS. (See Chapter 5 of the RIA.) This analysis found that, while there are additional costs to building a coal-fired power plant with CCS, there are also climate and human health benefits, as well as potential for revenue from enhanced oil recovery.  These benefits would outweigh regulatory costs under a range of assumptions.  See RIA chapter 5.
Natural gas affects the price and availability of fertilizer for farmers
Commenters 3236, 9193, and 8906 state the cost and availability of natural gas affects the price and availability of fertilizer for farmers and ranchers. Also, farmers and ranchers could be affected in another, more direct way because natural gas is the principal feedstock in the production of nitrogen fertilizer, which is a vital input for farmers and ranchers to grow crops. Commenter 8742 states that coal is an inexpensive, abundant, and reliable source of energy, and in Georgia, coal supplies most of the electricity. However, Georgia Power is seeking to close 15 coal-fired generators across the state, and commenter is concerned there will be a shortage of electric generation capacity to replace these coal-fired plants. The cost and availability of natural gas affects the price and availability of fertilizer for farmers. Natural gas is the principal feedstock in the production of nitrogen fertilizer, which is a vital input for farmers to grow crops. Commenter anticipates that as coal use becomes more limited, the demand for natural gas will increase, raising input costs for farmers.

Commenter 10032 states opposition to the regulation of greenhouse gas emissions, that carbon dioxide is naturally present in the atmosphere, that these regulations will impose added energy costs on the economy and will result in little or no impact on world temperatures or climate. Commenter states the rule will cost more for utilities and these costs are always passed on to rate payers. Farmers and ranchers will experience higher input costs because of the Proposed Standard, that resource-based industries are price takers, not price makers, and that they cannot pass higher input costs on to their customers. Commenter continues (10032) that the price and availability of fertilizer is affected by cost/availability of natural gas because natural gas is the principal feedstock in nitrogen fertilizer production. Natural gas price increases or price volatility will increase fertilizer and other input costs for farmers and ranchers.
Commenter 9193 states increases in other energy prices, fertilizer and machinery will hold negative consequences for agriculture while at the same time making U.S. farmers less competitive internationally.
Commenter 8906 states that farmers and ranchers are primarily end-users of the products from power plants and, thus, must completely depend on those who operate and own them.
The EPA's modeling, conducted using the Integrated Planning Model (IPM), as well as modeling conducted by the U.S. Energy Information Administration (EIA), showed that new generating capacity built through the period of analysis would be in compliance with the standard the baseline scenario, and as a result, there would be no change in behavior as a result of the standard. This finding held true even under a number of alternative scenarios. (See Chapter 4 of the RIA.) As a result, the EPA projected there would be negligible costs, benefits, energy impacts (including changes to natural gas prices), or other economic impacts associated with the rule in the period of analysis.  Further, although the EPA is sympathetic to these comments, one reason coal has been inexpensive is that environmental externalities have not been priced, but rather borne by those experiencing uncontrolled emissions.  
Impact on rural communities
Commenter 9382 states that the proposed GHG NSPS rule would effectively prohibit construction of new coal-fired generation in Indiana.  The rule's effect will devastate state economies like Indiana's because it ends the development of new coal-fired power plants placing the commenter's members at great risk. Commenter explains that their rural members will suffer the most adverse economic impacts from EPA's proposed GHG rules; that transitioning electric utility generation from coal to natural gas will result in stranded coal-fired EGUs, require significant additional investment in natural-gas fired generation, and ultimately, result in higher electricity rates. The 1935 Rural Electrification Act provided rural electrical cooperatives loans so that electricity could be brought to the most rural areas, and due to the regulation, coal- fired electricity generation is becoming prohibitively expensive.  Commenter 9382 adds it would be difficult to obtain funding from the Rural Utilities Service or otherwise for the type of experimental technology that would be necessary to build new coal-fired generation if EPA's proposal is finalized. Rural electric cooperatives face specific barriers due to our size, not-for-profit status, and greater proportion of residential customers as compared to industrial customers, all of which cause cooperatives and our members to feel the adverse consequences of EPA regulation more acutely. In addition, cooperatives serve rural areas and have a higher proportion of lower income and elderly customers, who are more vulnerable to rate increases. Commenter continues that although Indiana has abundant coal resources, it is not located sufficiently close to oil and gas production facilities such that partial CCS with EOR will never be economically feasible. In contrast, all of the partial CCS projects EPA analyzed in the proposal will utilize the captured CO2 for EOR. The unavailability of EOR would only increase the net costs of partial CCS in Indiana. In addition, there are significant potential costs related to transportation and the deep wells needed for sequestering carbon that are not accounted for in EPA's analysis of partial CCS projects, as discussed above.
Commenter 10022 states that uncertainty associated with fuel prices and regulatory compliance costs make it difficult to provide effective solutions to reduce the cost of electricity for Alaskans. The proposed NSPS does not facilitate needed solutions to Alaska's high-energy rates; in fact, it further inhibits development and technological improvements to the Alaskan power sector.
The coal industry is unquestionable undergoing great change, but this is due to macro-economic factors unrelated to the present rule. See RIA chapter 4. Even in states in the heart of coal mining areas, coal capacity is being replaced with NGCC, due to the lower price of NGCC.  See, e.g. Washington Post articles of Nov. 23, 2012 and July 23, 2015 (available in the docket for this rulemaking) concerning replacement of coal capacity in Kentucky with NGCC.  Note that the commenter 9382 concerns regarding sequestration siting issues are at least partially alleviated because the final standard of performance can be achieved by means not involving sequestration.
Navajo coal-related resources
Commenter 10103 states the Navajo Nation ("Nation") may be significantly affected by EPA's Proposed Rule and relies heavily on income from the sale and use of the coal located on its lands: it is the landlord for two large coal-fired power plants (the Navajo Generating Station and the Four Corners Power Plant) and associated coal mines also located on Navajo lands, and in fact is the owner of one of those mines. Commenter adds the Nation may acquire an ownership interest in all or part of the Navajo Generating Station ("NGS"), and although the Nation does not currently have and is not currently aware of plans for the development and construction of a new fossil fuel-fired electric utility generating unit on Navajo lands, the Nation maintains an interest in regulations and policies that may impact the construction and operation of power plants on its lands and the sale of the Nation's coal, both of which affect the Nation's ability to sustain its economy.
Commenter 10103 states assurances must be integrated into the proposed standards for new sources so that the continued use of coal is not made impossible or nearly impossible, and its coal reserves are its most saleable natural resources. The Nation does fully support the search for and use of alternative forms of renewable energy and continues its efforts towards developing a comprehensive energy strategy that will establish its energy independence and sustain its economy. 
The present proceeding concerns new fossil fuel-fired capacity exclusively, and so does not directly impact issues of sale of coal to existing facilities.
A standard that requires CCS on new coal plants guards against undue climate risk
Commenter 9035 states recent energy market developments having nothing to do with GHG regulation, such as the availability of inexpensive natural gas and the regulation of other pollutants, have created conditions under which the GHG emissions intensity of electricity generation is declining. Aside from one facility far along in the planning process and specifically exempt from the Proposal, construction of new conventional coal plants is currently not foreseen because natural gas prices are expected to remain very low through 2024 (when the Clean Air Act requires that the rule be reevaluated). For this reason, the EPA estimates that there will be no cost for industry compliance with the Proposal as compared with the status quo. Commenter adds that it is important to recognize that energy price projections are often wrong. Significant increases in natural gas prices may renew interest in new coal plants. Issuing a standard that allows construction of new high-emitting coal plants without a CCS requirement therefore poses a nontrivial risk to our climate. Given their long lifetimes, construction of new high-emitting coal plants could lock in their higher emissions for many decades to come, exacerbating the economic challenge the United States faces in reducing its GHG emissions. Commenter 9685 states that the benefits of extended life expectancy are significant and must be reflected in any cost-benefit analysis. Commenter includes excerpt from an attached document to support their point. Commenter considers this an unacceptable threat to the public health and welfare of the United States.
Commenter 9514 states climate stabilization requires immediate, deep reductions in emissions from the EGU sector. CO2 emissions from power plants remain the single largest source of U.S. greenhouse gas pollution and are a significant component of global emissions. Without emissions controls for this sector, it will be impossible to stabilize atmospheric greenhouse gas emissions at a safe level. (The commenter discussed the scope of emissions from coal and natural gas fired power plants.) 
Power plants are the biggest domestic emitters of carbon pollution. While companies building power plants today are already making cleaner generation choices, such as natural gas combined cycle or coal with CCS, the rule would lock in a lower carbon future and make sure this progress continues.  The plants built under this standard would be cleaner than the average coal unit operating today  -  which emits over 4 million metric tonnes of CO2 a year. By comparison, a new natural gas plant would emit 1.7 million tonnes a year, or about 2.3 million metric tonnes less; and a new, modern coal unit would emit no more than 3 million tonnes per year, or about 1 million tonnes less.  See preamble section V.K.

The EPA's modeling, conducted using the Integrated Planning Model (IPM), as well as modeling conducted by the U.S. Energy Information Administration (EIA), showed that new generating capacity built through the period of analysis would be in compliance with the standard the baseline scenario, and as a result, there would be no change in behavior as a result of the standard. This finding held true even under a number of alternative scenarios. As a result, the EPA projected there would be negligible costs, benefits, or energy impacts (including changes to natural gas prices) associated with the rule in the period of analysis. In addition, the Regulatory Impact Analysis for the rule included several illustrative analyses, examining the costs of the rule under a range of natural gas prices and the cost associated with building a coal plant with CCS. (See Chapter 5 of the RIA.) This analysis found that, while there are additional costs to building a coal-fired power plant with CCS, there are also climate and human health benefits which outweigh those costs under a range of assumptions, as well as potential for revenue from enhanced oil recovery.
EPA needs to address/regulate existing power plants
Commenter 10961 states EPA must enact the most aggressive, rapid, and technologically feasible emissions cuts to emissions of carbon dioxide from power plants under its Clean Act Authority, and expand them to existing plants. The draft proposal does not address existing coal-fired power plants, and would therefore grandfather and maintain this massive carbon pollution source for decades to come, well beyond the time window for averting climate catastrophe. The economics of the electricity industry suggest that the autonomous closing of existing coal-fired plants will be far too slow to significantly reduce future emissions. Some utilities are already moving away from coal and toward natural gas or new power plants, for purely economic reasons, while using various subterfuges and loopholes to maintain their existing coal-fired power plants. Therefore, the EPA's proposed rule would change little utility behavior from a baseline scenario assuming low natural gas prices, and is not adequate to the Clean Air Act. The law requires EPA to curtail lethal threats to human life and health, not merely proceed through regulatory motions that codify and endorse existing market trends. The purpose of the Clean Air Act is not to envelop America's pollution sources in a regulatory framework for its own sake, devoid of material effect, but to actually reduce human mortality.
On June 2, 2014, EPA issued a proposal for state goals to reduce CO2 emissions from fossil fuel-fired EGUs. Comments on that rulemaking are outside the scope of this rulemaking, which focuses only on new EGUs. 
Change vastly outweighs the cost to implement this technology 
Commenter 2983 states it is critical that the proposed EPA emissions regulations require substantial emissions reductions, explaining that reductions in emissions are feasible through existing and developing technology, and the real danger associated with inaction on climate change ensures that carbon capture technology (e.g. scrubbers) need to be improved, made more efficient, and remove more carbon and other pollutants. Many utility companies, energy regulatory bodies, and energy center developers will argue that implementation of any proposed rulings that limit GHG emissions are too costly; however, commenter states that this is false. The cost of inaction on climate change vastly outweighs the cost to implement this technology.
The EPA thanks the commenter and notes that the Regulatory Impact Analysis for the rule includes several illustrative analyses, examining the costs of the rule under a range of natural gas prices and the cost associated with building a coal plant with CCS. This analysis found that, while there are additional costs to building a coal-fired power plant with CCS, there are also climate and human health benefits which outweigh the costs under a range of assumptions.
Green jobs created and consumer savings
Commenter 10093 states EPA's regulation of carbon pollution can also play an important role in setting the U.S. on a path toward a clean energy economy, and this transition brings twin benefits: it creates green jobs and saves money for consumers.
Commenter 5605 states new clean energy technologies that produce less carbon pollution will create a new generation of green jobs for Western North Carolina, explaining that North Carolina solar industry or North Carolina rural energy portfolio is responsible for more than 15,000 jobs since 2007. Western North Carolina is the hub of clean energy already and the state has a strong solar manufacturing center. Commenter concludes that taking action to reduce much of the carbon pollution responsible for climate change, such as increasing investment in renewable energy which will create jobs and help the economy in Western North Carolina.
Commenter 2983 states implementation of emissions reductions measures does not mean that net jobs will be lost. The clean energy sector is growing, which provides permanent jobs in an important and developing market (http://articles.latimes.com/2013/mar/19/business/la-fi-mo-green-jobs-20130319). Commenter continues that there is a need for a shift in jobs from mining, construction and operation of power plants toward installation of wind turbines, photovoltaic cells, and energy efficiency measures, and explains that a paradigm shift in the way our energy and associated jobs are structured will bring about the changes we need to address climate change.
The EPA thanks the commenter for this information.
Sea level rise modeling
Commenter 10091 references the Fifth Assessment Report (AR5) of the Intergovernmental Panel on Climate Change and states how the sea level rise module in DICE was constructed is inaccurately characterized by the IWG2013 report. The IWG2013 report describes the development of the DICE sea level rise scenario as: "The parameters of the four components of the SLR module are calibrated to match consensus results from the IPCC's Fourth Assessment Report (AR4). However, in IWG2013 footnote "6" the methodology is described this way: "The methodology of the modeling is to use the estimates in the AR4." "Using estimates" and "calibrating" are two completely different things. Calibration implies that the sea level rise estimates produced by the DICE sea level module behave similarly to the IPCC sea level rise projections and instills a sense of confidence in the casual reader that the DICE projections are in accordance with IPCC projections. However this is not the case. Consequently, the reader is misled. In fact, the DICE estimates are much higher than the IPCC estimates. This is even recognized by the DICE developers. From the same reference as above: "The RICE [DICE] model projection is in the middle of the pack of alternative specifications of the different Rahmstorf specifications. Table 1 shows the RICE, base Rahmstorf, and average Rahmstorf. Note that in all cases, these are significantly above the IPCC projections in AR4." That the DICE sea level rise projections are far above the mainstream estimated can be further evidenced by comparing them with the results produced by the IWG-accepted MAGICC modelling tool (in part developed by the EPA and available from http://www.cgd.ucar.edu/cas/wigley/magicc/).  
Commenter 10091 continues, stating that using the MESSAGE scenario as an example, the sea level rise estimate produced by MAGICC for the year 2300 is 1.28 meters - a value that is less than 40% of the average value of 3.32 meters produced by the DICE model when running the same scenario (see figure below). The justification given for the high sea level rise projections in the DICE model (Nordhaus, 2010) is that they well-match the results of a "semi-empirical" methodology employed by Rahmstorf (2007) and Vermeer and Rahmstorf (2009). However, subsequent science has proven the "semi-empirical" approach to projecting future sea level rise to be unreliable. For example, Gregory et al. (2012) examined the assumption used in the "semi-empirical" methods and found them to be unsubstantiated. Gregory et al (2012) specifically refer to the results of Rahmstorf (2007) and Vermeer and Rahmstorf (2009): The implication of our closure of the [global mean sea level rise, GMSLR] budget is that a relationship between global climate change and the rate of GMSLR is weak or absent in the past. The lack of a strong relationship is consistent with the evidence from the tide-gauge datasets, whose authors find acceleration of GMSLR during the 20th century to be either insignificant or small. It also calls into question the basis of the semi-empirical methods for projecting GMSLR, which depend on calibrating a relationship between global climate change or radiative forcing and the rate of GMSLR from observational data (Rahmstorf, 2007; Vermeer and Rahmstorf, 2009; Jevrejeva et al., 2010). In light of these findings, the justification for the very high sea level rise projections (generally exceeding those of the IPCC AR5 and far greater than the IWG-accepted MAGICC results) produced by the DICE model is called into question and can no longer be substantiated. Given the strong relationship between sea level rise and future damage built into the DICE model, there can be no doubt that the SCC estimates from the DICE model are higher than the best science would allow and consequently, should not be accepted as a reliable estimate of the social cost of carbon. Commenter did not investigate the sea level rise projections from the FUND or the PAGE model, but suggest that such an analysis must be carried out prior to extending any confidence in the values of the SCC resulting from those models - confidence that we demonstrate cannot be assigned to the DICE SCC determinations.  
EPA recognizes that sea level rise projections are an area of ongoing research. One key issue involves projections of melt from the Greenland and West Antarctic ice sheets. The IPCC AR5 report notes there is a possibility of sea level rise "substantially above" their best estimate of a likely range because of uncertainties regarding the response of the Antarctic ice sheet (AR5 Working Group I, Chapter 13). In AR5 the IPCC also discusses semi-empirical methods, stating a low confidence in projections based on such methods, which calibrate a mathematical model against observations rather than projecting individual processes. However, the IPCC did not entirely discount these methods. Further supporting the use of semi-empirical methods, the U.S. National Climate Assessment uses an average of the high end of semi-empirical projections in order to define their "Intermediate-High" Scenario (Parris et al., 2012). Therefore, it is reasonable for one out of three models used to estimate the social cost of carbon (SC-CO2) to include some reliance upon semi-empirical methods. 
EPA is aware that more sophisticated yet still relatively simplified climate models, such as MAGICC, could be used to replace the highly simplified climate science components of the three IAMs. However, given the range of climate models available and the technical issues associated with such a change, replacing the climate modules or other structural features of the IAMs requires additional investigation before it can be applied to social cost of carbon estimation. EPA will continue to follow and evaluate the latest science on climate modeling and, along with other members of the interagency working group, is seeking external expert advice on the technical merits and challenges of potential approaches to updating this component of the IAMs in future revisions to the social cost of carbon estimates.  See response to comments 4.4-2 for more detailed discussion about the climate science components of the models used to estimate the social cost of carbon and section 4.4 generally for response to comments on the social cost of carbon.
Externalities
Commenter 10093 states because fossil fuels have historically benefited from large subsidies, and because the externalities created by dirty energy have not been included in the price of energy, renewable energy sources have struggled to become cost-competitive, regulating carbon pollution would help level the playing field by reducing the externalities--namely, greenhouse gases--that fossil fuel plants are allowed to produce without paying their true costs, and turning the United States toward a clean energy economy would reduce these costs and mitigate expensive fluctuations in energy prices that hurt American consumers and businesses.
Commenter 10091 states carbon dioxide is known to have a positive impact on vegetation, with literally thousands of studies in the scientific literature demonstrating that plants (including crops) grow stronger, healthier, and more productive under conditions of increased carbon dioxide concentration. A recent study (Idso, 2013) reviewed a large collection of such literature as it applies to the world's 45 most important food crops (making up 95% of the world's annual agricultural production). Idso (2013) summarized his findings on the increase in biomass of each crop that results from a 300ppm increase in the concentration of carbon dioxide under which the plants were grown. This table is reproduced below, and shows that the typical growth increase exceeds 30% in most crops, including 8 of the world's top 10 food crops (the increase was 24% and 14% in the other two). Idso (2013) found that the increase in the atmospheric concentration of carbon dioxide that took place during the period 1961-2011 was responsible for increasing global agricultural output by 3.2 trillion dollars (in 2004-2006 constant dollars). Projecting the increases forward based on projections of the increase in atmospheric carbon dioxide concentration, Idso (2013) expects carbon dioxide fertilization to increase the value of agricultural output by 9.8 trillion dollars (in 2004-2006 constant dollars) during the 2012-2050 period. This is a large positive externality, and one that is insufficiently modeled in the IAMs relied upon by the IWG in determining the SCC. In fact, only one of the three IAMs used by the IWG has any substantial impact from carbon dioxide fertilization, and the one that does, underestimates the effect by approximately 2-3 times. 
Commenter 10091 continues, stating that the FUND model has a component which calculates the impact on agriculture as a result of carbon dioxide emissions, which includes not only the impact on temperature and other climate changes, but also the direct impact of carbon dioxide fertilization. The other two IAMs, DICE and PAGE by and large do not (or only do so extremely minimally; DICE includes the effect to a larger degree than PAGE). Consequently, lacking this large and positive externality, the SCC calculated by the DICE and PAGE models is significantly larger than the SCC determined by the FUND model (for example, see Table A5, in the IWG 2013 report). But even the positive externality that results from carbon dioxide fertilization as included in the FUND model is too small when compared with the Idso (2013) estimates. FUND (v3.7) uses the following formula to determine the degree of crop production increase resulting from atmospheric carbon dioxide increases (taken from Anthoff and Tol, 2013a):  
Additionally, Commenter10091 states column 8 in the table below shows the CO2 fertilization parameter (gamma r) used in FUND for various regions of the world (Anthoff and Tol, 2013b). The average CO2 fertilization effect across the 16 regions of the world is 11.2%. While this number is neither really weighted, nor 19 r) used in FUND for various regions of the world (Anthoff and Tol, 2013b). The average CO2 fertilization effect across the 16 regions of the world is 11.2%. While this number is neither really weighted, nor 19 weighted by the specific crops grown, it is clear that 11.2% is much lower than the average fertilization effect compiled by Idso (2013) for the world's top 10 food crops (35%). Further, Idso's fertilization impact is in response to a 300ppm CO2 increase, while the fertilization parameter in the FUND model is multiplied by ln(CO2 t/275) which works out to 0.74 for a 300ppm CO2 increase. This multiplier further reduces the 16 region average to 8.4% for the CO2 fertilization effect - some 4 times smaller than the magnitude of the fertilization impact identified by Idso (2013). Although approximately four times too small, the impact of the fertilization effect on the SCC calculation in the FUND model is large.
Commenter 10091 continues, stating according to Waldhoff et al. (2011), if the CO2 fertilization effect is turned off in the FUND model (v3.5) the SCC increases by 75% from $8/tonCO2 to $14/tonCO2 (in 1995 dollars). In another study, Ackerman and Munitz (2012) find the effective increase in the FUND model to be 20 even larger, with CO2 fertilization producing a positive externality of nearly $15/tonCO2 (in 2007 dollars). Clearly, had the Idso (2013) estimate of the CO2 fertilization impact been used instead of the one used in FUND, the resulting positive externality would have been much larger, and the resulting net SCC been much lower. This is just for one of the three IAMs used by the IWG. Had the more comprehensive CO2 fertilization impacts identified by Idso (2013) been incorporated in all the IAMs, the three-model average SCC used by the IWG would be been greatly lowered, and likely even become negative in some IAM/discount rate combinations. 
The commenter is not correct that the final standards of performance are without benefits.  It is correct that the base case modeling the EPA performed for this rule projects that, even in the absence of this action, new fossil fuel  -  fired capacity constructed through 2022 and the years following will most likely be NGCC capacity that complies with the final standards.  This is due to current and projected economic market conditions.  See generally RIA chapter 4.  Nonetheless, there could be circumstances where new coal-fired capacity is built  -  commenters to EPA's initial proposal maintained adamantly that this was a possibility (although no specific examples have as yet been provided).  In that event, EPA conducted further analysis which shows that there would be net quantified monetary benefits to society in the form of reduced CO2 emissions and secondary fine PM emissions from SCPC facilities (due to reduced SO2 emissions).  See RIA chapter 5.2.  That is, for each new SCPC facility that would be constructed, the cost of meeting a 1400 lb/MWh-gross standard is more than offset by the monetized benefits of the CO2 and secondary fine PM under a range of assumptions.  This analysis does not quantify other benefits of the standard. This analysis does not quantify other benefits of the standard.  The standard provides certainty for new plants (see, for example, the AEP FEED study associated with the Mountaineer project, where the company states that it was abandoning the project due to regulatory uncertainty), and a means to enable carbon control technology that will allow future coal  -  fired capacity in a reduced carbon economy.  The commenters are also correct as a matter of law that some type of section 111 (b) standard is a legal condition precedent to section 111 (d) guidelines for existing sources, but this rule has positive benefits with or without consideration of that additional factor. Power plants are the biggest emitters of carbon pollution. While companies building power plants today are already making cleaner generation choices, such as natural gas combined cycle or coal with CCS, the proposed rule would lock in a lower carbon future and make sure this progress continues.  The plants built under this standard would be cleaner than the average coal unit operating today  -  which emits over 4 million metric tonnes of CO2 a year. By comparison, a new natural gas plant would emit 1.7 million tonnes a year, or about 2.3 million metric tonnes less; and a new, modern coal unit would emit no more than 3 million tonnes per year, or about 1 million tonnes less. As one commenter notes, uncontrolled emissions create negative externalities that impact the health and well-being of individuals across the country.  See generally preamble section V.K.

Regarding comments on carbon dioxide fertilization, in particular treatment in the models used to estimate the social cost of carbon, see detailed response in 4.4-6 and see 4.4-1 for details about the models and social cost of carbon methodology.

Regulatory Impact Analysis (RIA)
No benefits makes standard arbitrary and capricious
Multiple commenters (10050, 7977, 10870, 10034, and 10097) remark that EPA states the proposed standards will result in minimal carbon dioxide (CO2) emission reductions and no quantified benefits. Commenter explains that the proposed rule does not advance the stated objective of reducing CO2 and will not affect global GHG concentrations, thus rendering the proposed standards arbitrary and capricious. One commenter (10870) states EPA concluded that even without the Proposed Rule, "(i) existing and anticipated economic conditions mean that few, if any, solid fossil fuel-fired EGUs will be built in the foreseeable future; and (ii) electricity generators are expected to choose new generation technologies (primarily natural gas combined cycle) that would meet the proposed standards." Commenter continues that assuming EPA's RIA's findings are correct, there is no reason to require CCS for coal-fired steam electric plants since the RIA projects there will be few to no new coal-fired electric utility generating units (EGUs) built in the foreseeable future. Commenter 9666 states Chapter 3 of the RIA does not state how this rule would affect climate change or otherwise provide a "rationale for rulemaking", and in Chapter 5, the RIA notes that, "under a wide range of likely electricity market conditions," EPA estimates that "industry will choose to construct new units that already meet the standards of this proposed rulemaking," leading the commenter to state that advancing such mutually incompatible positions is arbitrary and capricious. Commenters 9666 and 9201 state EPA has not fulfilled its obligations under statute and Executive Order by asserting there will be no costs and benefits to this proposed rule and not conducting an analysis of the impacts of the proposed rule, making the proposal arbitrary, capricious, and beyond the delegation of authority under the CAA. Commenter cites OMB Circular A-4 "three basic elements" that are missing from RIA)  and states EPA does not include a statement of the need for the proposed action, an examination of alternative approaches, or an evaluation of the proposed rule's real costs to the EGU sector. 
Commenter 1624 states his analysis of EPA's values suggests they were chosen to allow efficient gas powered units to achieve the set values without any additional effort. The choice seems intended to favor the use of natural gas. The proposed values do not appear to be based on protecting human health or the environment.
The commenter is not correct that the final standards of performance are without benefits.  It is correct that the base case modeling the EPA performed for this rule projects that, even in the absence of this action, new fossil fuel  -  fired capacity constructed through 2022 and the years following will most likely be NGCC capacity that complies with the final standards. This is due to current and projected economic market conditions.  See generally RIA chapter 4. Nonetheless, there could be circumstances where new coal-fired capacity is built  -  commenters to EPA's initial proposal maintained adamantly that this was a possibility (although no specific examples have as yet been provided).  In that event, EPA conducted further analysis which shows that there would be net quantified monetary benefits to society in the form of reduced CO2 emissions and secondary fine PM emissions from SCPC facilities (due to reduced SO2 emissions).  See RIA chapter 5.2.  That is, for each new SCPC facility that would be constructed, the cost of meeting a 1,400 lb/MWh-gross standard is more than offset by the monetized benefits of the CO2 and secondary fine PM under a range of assumptions. This analysis does not quantify other benefits of the standard.  The standard provides certainty for new plants (see, for example, the AEP FEED study associated with the Mountaineer project, where the company states that it was abandoning the project due to regulatory uncertainty), and a means to enable carbon control technology that will allow future coal  -  fired capacity in a reduced carbon economy.  The commenters are also correct as a matter of law that some type of section 111 (b) standard is a legal condition precedent to section 111 (d) guidelines for existing sources, but this rule has positive benefits with or without consideration of that additional factor.   Power plants are the biggest domestic emitters of carbon pollution. While companies building power plants today are already making cleaner generation choices, such as natural gas combined cycle or coal with CCS, the proposed rule would lock in a lower carbon future and make sure this progress continues.  The plants built under this standard would be cleaner than the average coal unit operating today  -  which emits over 4 million metric tonnes of CO2 a year. By comparison, a new natural gas plant would emit 1.7 million tonnes a year, or about 2.3 million metric tonnes less; and a new, modern coal unit would emit no more than 3 million tonnes per year, or about 1 million tonnes less. In 2009, the EPA Administrator found that elevated concentrations of greenhouse gases in the atmosphere may reasonably be anticipated both to endanger public health and to endanger public welfare. It is thus entirely reasonable for the EPA to exercise its lawful discretion to adopt technology-based standards to control emissions from the source category that is substantially contributing to that air pollution which endangers.  .
Call for 8-yr review
Commenter 9422 states the proposed rule should be withdrawn and a new proposed rule should be issued that provides a standard for coal-fired units using the BSER that is adequately demonstrated and achievable by a coal-fired unit. Commenter offers alternatively, since there is currently no true system of emissions reduction available for fossil fuel-fired utility units and the preamble indicates that the "proposed rule will result in negligible CO2 emission changes, quantified benefits, and costs by 2022", there is no reason to proceed with this rulemaking and it would be prudent to withdraw the proposed rule or propose an NSPS that simply states that there are no available emission reduction systems at this time and no CO2 standards apply to electric utility units. A BSER analysis could then be conducted during the periodic 8 year review of the NSPS to determine if there is a CO2 emissions reduction system that is achievable and adequately demonstrated at that time.
The EPA disagrees. The standard of performance provides enormous emission benefits comparing a new SCPC with an SCPC meeting the standard of performance predicated on performance of partial CCS.  See preamble section V.K.
Call for periodic reanalysis 
Commenter 10034 states EPA should commit to measuring commenter's metrics and assumptions on a regular basis to provide timely feedback on the rule's outcomes, costs, implementation, and paperwork burdens.
CAA Section 111(b) requires that the new source performance standards (NSPS) be reviewed, and potentially revised, every eight years. The EPA will consider the available data at this time.
Call for measurement of outcomes
Commenter 10034 states determining linkages between the rule and the measured outcomes is necessary to ensure that the policy itself resulted in the desired outcomes, rather than other factors beyond the agency's control, and any result of this rule should be measured against this baseline, and the rule is only a "success" based on these metrics if it causes emissions reductions above and beyond what is already anticipated to occur absent this rule. The commenter continues EPA's primary stated outcomes are neither cohesive nor measurable, leaving the public and the agency few options for the retrospective review of this rule, and EPA should clearly define its baseline and how the proposed policy outcomes differ from those already expected to be achieved absent policy intervention. The commenter adds EPA should measure whether its standard has any adverse impacts on the power sector, national electricity prices, or the energy sector. The commenter also recommends outcomes measures.
These types of issues inform the eight year review mentioned in the response immediately above.
Appropriate to include co-benefits of other pollutants' reduction in cost-analysis
Commenter 9514 states EPA's estimation of the proposed rule's costs appropriately reflects these co-benefits and, more broadly, represents a reasoned and judicious analysis that fully complies with the dictates of the CAA. Commenter explains that 1) EPA correctly considered the co-benefits of reduced emissions of SO2 and NOx that would result from compliance with the proposed rule's CO2 emission limits; 2) acknowledges the co-benefits from reducing SO2 and NOx vary by location, and EPA observed that the locations of any new coal plants are uncertain; 3) EPA's recognition of co-benefits is consistent with the methodology it applied in the MATS rulemaking, which also addressed the rule's positive impacts on emissions of related pollutants; and 4) this methodology is also consistent with scientific studies linking policies to reduce greenhouse gases with shorter-term air quality co-benefits.
The EPA thanks the commenter for this comment recognizing the importance of co-benefits in the analysis of costs and benefits. See also responses on this issue in chapter 6.4 of this RTC.
No new modeling since 2012 proposed rule 
Commenters 9666 and 10023 state EPA undertook no new modeling runs [since the April 2012 proposed rule] even though EPA claims it has made "significant revisions" to the proposal.  Id. at 2-1, 5-6. Commenter 10023 continues EPA does not acknowledge the costs to the electric sector of the fact that this proposed rule, and its April 2012 predecessor, has had a considerable effect on companies and organizations that were planning prior to April 2012 to construct new EGUs and those that would otherwise plan to build such units absent this proposed rule.
The EPA updated its baseline modeling between the proposal and final rules. The EPA's modeling, conducted using the Integrated Planning Model (IPM), as well as modeling conducted by the U.S. Energy Information Administration (EIA) showed that new generating capacity built through the period of analysis would be in compliance with the standard in the baseline scenario, and as a result, the requirements of the rule would not result in any behavior changes and therefore no costs and no quantified benefits. 
EPRI analysis disagrees with EPA's results 
Commenter 10095 states a November 2013 report completed by EPRI analyzed the impacts of this proposal on the U.S. electric sector and arrived at a drastically different conclusion. EPRI compared the results of 12 scenarios that incorporated EPA's proposed standards to a baseline that allowed new coal-fired plants to be constructed without CCS. EPRI's scenarios evaluated various natural gas price paths, the availability of new nuclear and new inter-regional transmission, and the lifetime of the existing coal fleet. Additional costs are incurred by the electricity sector in all scenarios due to the proposed standards. The costs range from $15 billion to $293 billion through 2050 (net present value in 2010). As required by Executive Order 12866 (1993), EPA must assess these costs and determine that the benefits of the proposal, if any, justify the costs.
Commenter did not provide a copy of the referenced report. Based on date of the report, any assumptions about gas price and availability are older than those used by EIA and EPA in this rule, and do not fully capture recent trends.  Additionally, based on the summary provided by the commenter, it appears that these scenarios might have considered reduced availability of new transmission, which is not a reasonable assumption. 

As required under Executive Order 12866, the EPA conducts benefit-cost analyses for major Clean Air Act rules, and has done so here. While such analysis can help to inform policy decisions, as permissible and appropriate under governing statutory provisions, the EPA does not use a benefit-cost test (i.e., a determination of whether monetized benefits exceed costs) as the sole or primary decision tool when required to consider costs or to determine whether to issue regulations under the Clean Air Act, and is not doing so here See Memorandum "Consideration of Costs and Benefits under the Clean Air Act" available in the rulemaking dockets, EPA-HQ-OAR-2013-0495 (new sources) and EPA-OAR-HQ-2013-0603.The EPA's modeling, conducted using the Integrated Planning Model (IPM), as well as modeling conducted by the U.S. Energy Information Administration (EIA) showed that new generating capacity built through the period of analysis would be in compliance with the standard in the baseline scenario, and as a result, the requirements of the rule would not result in any behavior changes and therefore no costs and no quantified benefits. (See Chapter 4 of the RIA.) Additionally, we also present an analysis of the project-level costs of a newly constructed coal-fired steam generating unit with partial CCS that meets the requirements of this final rule alongside the project-level costs of a newly constructed coal-fired unit without CCS. This analysis in RIA chapter 5 indicates that the quantified benefits of the standards of performance would exceed their costs under a range of assumptions.
RIA incomplete (analyses missing)
Several commenters (3176, 7977, 10048, and 9666) state analyses were missing from the RIA, making it incomplete. Commenter 10023 states the RIA does not satisfy the requirements of section 317 of the CAA, including the requirements to analyze how the estimated costs of compliance would vary depending on the effective date of the proposed standard; how the estimated costs of compliance would vary with the development of less expensive, more efficient measures of compliance with standard; the potential inflationary or recessionary impacts of the rule; the effects of the rule on consumer costs; and the effects of the rule on energy use. Commenter 7977 added that the RIA does not estimate the consumer sensitivity to changes in electricity prices or the price elasticity of demand, explaining that the commenter's modeling demonstrates that changes in electricity prices are associated with second-order economic implications, including changes in employment and economic growth. Commenter states that these second-order costs of environmental policy frequently outweigh the costs of actual compliance.
Comment 3176 states before finalizing a GHG standard, EPA should perform a job impact analysis, particularly the proposed rule's effect on related industry, to assist in weighing the costs and benefits. 
Commenter 7977 states a long-term policy impact analysis should account for price elasticity, employment effects, the potential loss of energy-intensive manufacturing and heavy industry, and regional economic impacts, explaining that the commenter determined that, by preventing least-cost resources beyond 2022, this proposed rule will exacerbate the forecasted 25 percent increase in the real price of electricity in Kentucky between 2011 and 2025, and result in the loss of, or failure to, create approximately 30,000 full time jobs, with Kentucky's manufacturing sector being the most responsive to these changing prices. 
Commenter 7977 states the EPA has not incorporated utility risk assessment modeling into its economic analysis, noting future hydraulic fracturing regulations could result in natural gas and NGLs becoming uneconomical in the marketplace and without coal-fired generation, the economic consequences are "potentially devastating" for the United States. 
Commenter 7977 continues the EPA has not accounted for the increased threat to national security that accompanies the move to natural gas due to enhanced pipeline vulnerability. 
Commenter 7977 states excluding GHG impacts from fossil fuel extraction and transport, EPA's analysis of health and welfare impacts is incomplete. The proposed rule relies on EIA forecasts that indicate natural gas preference over coal within the eight-year NSPS time frame. Commenter explains recent studies suggest that lifecycle climate effects of shale gas are worse than coal over a 30-50 year timeframe and draws serious questions to its use as a transitional fuel to more renewable sources. Thus, lifecycle GHG emissions from increased natural gas production and transportation should be included in EPA cost-benefit analysis including health and welfare impacts.  
Commenter 10048 states EPA's analysis did not consider that certain areas of the country lack access to natural gas storage options. Commenter 9666 states the RIA included no analysis of the potential environmental, macroeconomic, or jobs impacts of the proposed rule because EPA assumes that the rule will not alter the status quo of projected new-build power plant types and, therefore, will have no impacts at all. 
Commenter 9666 states the RIA estimates future electricity production cost based on the average of predicted fuel prices, inflation rate, and the capital cost for SCPC and NGCC - using mean values for key inputs such as equipment costs and fuel prices that only change with time in a tranquil and well-behaved manner - which may be valid for projecting power costs averaged over a large geographic region. Commenter states this approach does not simulate the variability of site and business conditions confronted by decision-makers on a regional or individual project basis.
The EPA did consider the costs and benefits and other impacts of the proposed rule, in accord with Executive Orders 12866 and 13563. In response to commenters 3176 et al., this analysis also satisfies the economic assessment called for under section 317 of the Clean Air Act and is, for purposes of section 317(d), in the EPA's judgment, as extensive as practicable taking into account the agency's time, resources, and other duties and authorities.  This analysis is presented in the Regulatory Impact Analysis for the regulation (and, for purposes of CAA section 317 (b), was prepared in proposed form before publication of the proposed rule). In response to commenter 10023, the agency's analysis includes discussion of effects on energy use (see preamble section V.O.3 and sources there cited).  

Contrary to the assumptions of these comments, the IPM modeling for the RIA includes adjustments for existing regulations related to hydraulic fracturing (http://epa.gov/powersectormodeling.)  The RIA makes clear that the rule has only negligible impacts beyond a base case without the rule, and the commenters provide no basis for linking national security issues to incremental impacts from this rule.  The RIA also discusses a range of cases where prices rise to unexpected or unprecedented levels; EPA believes considering such cases addresses concerns that large changes in the impact of the rule might occur due to unexpected consequences of events like responses to national security disruptions, or to unanticipated regulatory restrictions on natural gas supplies.  

The "effective date of the standard" (section 317(c) (2)) has no effect on the rule's costs, since the trigger date for new source status is the date of proposal.  In addition, the EPA has taken action to assure that sources under development are not subject to the final standard of performance.  See preamble section III.J.  The EPA also structured the proposed and final standard to avoid more costly alternatives, but rejected the 'business as usual' option as not reasonably fulfilling the requirement of section 111 (a) to base standards on the performance of the best system of emission reduction adequately demonstrated.  

The EPA's analysis, which is supported by analysis by EIA, shows that new generation constructed is expected to meet these standards, even in the absence of this rule. As a result, we expect there would be no costs, benefits, energy, economic or employment impacts associated with this standards. This conclusion holds true under a number of alternative scenarios, including scenarios developed by EIA most likely to result in new coal-fired generation. See RIA chapter 4. With all of the sector-level modeling showing that there are not expected impacts from these standards, it is not possible to conduct additional macroeconomic or employment analysis requested. In Chapter 5 of the RIA, EPA presents two unit-level illustrative analyses. One shows the potential costs and benefits of the standards under a range of natural gas prices. In this analysis, it is only when levelized natural gas prices reach levels not seen in EIA data back to 1996 that an NGCC unit would become more expensive than a non-compliant coal unit. In the other, the EPA considers the costs and benefits of a compliant coal unit compared to a non-compliant unit. While there would be costs associated with this unit, the related health and environmental benefits would be greater the costs under a range of assumptions. Because these are illustrative analyses and not based on a real unit, it is not possible to conduct an employment analysis. 

We do not project changes in fuel use as a result of these standards, so there would not be changes in emissions related to extraction activities. 
Commenter 4814 states reducing global greenhouse gas emissions is a vital endeavor that will require cooperation and action from many segments of our economy, throughout the nation and in international activities. There are, however, regions of the country that will be more dramatically impacted by GHG emissions requirements, and the SSEB region is one such example. The economics of coal and natural gas, especially for electrical generation, have helped the region develop a critical manufacturing and industrial base leading to an improved quality of life not only for the residents of the South but also for the nation. To that end, EPA must consider the economic health of the region and its impact on the vibrancy and security of the national economy over the foreseeable future.
Commenter 9776 states as NMA's comments explain, numerous studies conclude that methane emissions from natural gas systems diminish or eliminate any GHG advantage in terms of life cycle GWP. However, EPA's proposed rule does not examine this issue whatsoever, despite its clear impact on EPA's decision in setting power plant standards. Commenter 9776 continues noting EPA's criticism of Federal Energy Regulatory Commission's (FERC) Draft Environmental Impact Statement (DEIS) on a proposed natural gas liquefaction and pipeline project as recently as this March. In EPA's comments, the agency recommended that FERC consider the extent to which the proposed project would potentially increase demand for natural gas and the environmental impacts associated with the potential increased production of natural gas, and quantify and consider the lifecycle GHG emissions associated with the proposed action. Commenter states that EPA advised FERC that the "methodologies for conducting that analysis are available and well developed." These and several other deficiencies EPA identified produced an "Environmental Concerns Insufficient Information" (referred to as an EC-2) rating of the FERC DEIS.
Commenter 9735 states the proposed NSPS rule does not sub-categorize emissions standards for the various types of coal, in particular the four main classifications of coal mined and used for electrical generation in this country: lignite, sub-bituminous, bituminous, and anthracite. No recognizing the regional differences in resources used for coal-fired power would lead to states like North Dakota, potentially being forced to purchase coal from other states instead of being able to utilize a low-cost, abundant resource found right in our backyard.
Commenter 9666 states the RIA included no analysis of the potential environmental, macroeconomic, or jobs impacts of the proposed rule because EPA assumes that the rule will not alter the status quo of projected new-build power plant types and therefore will have no impacts at all. 
Commenter 10555 states as fracking becomes more regulated, profit margins will decrease and prices will increase, and adds that the EPA does not take into account the economic impacts of the pressures it is putting on the natural gas industry in this proposed rulemaking.
Commenter 9765 states the EPA does not include all reasonable costs associated with EOR. Proposed Rule exclude costs of "land acquisition and right-of-way, permits and licensing, royalty allowances, economic development, project development costs, allowance for funds-used-during construction, legal fees, Owner's engineering, preproduction costs, furnishings, Owner's contingency, etc." The cost estimates also exclude site-specific considerations, such as seismic activity, local regulations, and accessibility. Commenter states that EPA should include these types of costs in its analysis in order to reach a meaningful conclusion. 
Commenter 10046 states effects of NSPS proposals on the economic health and viability of the industry have traditionally been the key focus of EPA assessments under EPA's historical approach to NSPS. EPA has carefully assessed whether the costs are within the range that could be absorbed while not unduly depressing economic viability, including whether or not they could in fact be passed on: Pressure Sensitive Tape and Label Surface Coating Industry; Kraft Pulp Mills; Basic Oxygen Process Furnaces; Beverage Can Surface Coating Industry;  Synthetic Organic Chemical Manufacturing Industry; Coal Preparation Plants. 
Commenter 9765 states regarding Section III, the term "energy requirements" in Section 111(a)(I) contemplates the energy requirements of the BSER. The proper considerations under a Section III analysis include topics like: how much energy does the BSER use, and is the additional power required to employ the BSER sufficiently reasonable to impose it upon all affected sources The EPA does not address the energy impact of CCS technology. Instead, the EPA focuses on whether the grid will have enough power given a lack of new coal-fired power plants. See, e.g., 79 Fed. Reg. at 1481.  One highly likely adverse impact of requiring partial CCS on all new coal-fired power plants is the enormous amount of electricity lost to powering the CCS technology. As with any large industrial equipment, CCS technology needs electrical power to operate. When installed on an electric utility generating unit (EGU), CCS equipment leeches power from the generation process, causing a parasitic reduction in total available power to the grid. Estimates of the energy penalty that each facility will incur by incorporating CCS technology run as high as 20% to 35% depending on the technology used. The energy penalty associated with CCS technology has an additional consequence that the EPA fails to acknowledge; an increase in the rate at which America literally burns through its valuable natural resources. In order to make up for the parasitic reduction in energy due to CCS, facilities will be required to bum more coal. Based on current efficiencies, facilities will need an additional 25% to 33% more coal to continue producing the same amount of energy as they would without CCS. Id. Through the burning of more coal, each facility has the potential to produce higher quantities of pollutants that facilities must then manage, including sulfur oxides (SOx), nitrous oxides (NOx), carbon monoxide (CO), particulate matter (PM), coal ash, and mercury (Hg). Whether facilities can manage the increase in other pollution streams is another question the EPA does not answer. Commenter contends that because the EPA did not consider fully the environmental impacts associated with implementing CCS technology, its action in proposing this rule is arbitrary, capricious, and contrary to the factors set forth in Section 111. In light of all of the issues presented in this subsection, it is clear that the EPA did not show that CCS is adequately demonstrated technology. The EPA's failure to fully consider the statutory factors, as well as its failure to rationally decide the meaning of the limited evidence it has, require the EPA to withdraw this Proposed Rule. 
The EPA did consider the costs and benefits and other impacts of the proposed rule, in accord with Executive Orders 12866 and 13563. This analysis also satisfies the economic assessment called for under section 317 of the Clean Air Act and is, for purposes of section 317(d), in the EPA's judgment, as extensive as practicable taking into account the agency's time, resources, and other duties and authorities.  This analysis is presented in the Regulatory Impact Analysis for the regulation (and, for purposes of CAA section 317 (b), was prepared in proposed form before publication of the proposed rule). In response to commenter 10023, the agency's analysis includes discussion of effects on energy use (see preamble section V.O.3 and sources there cited).  The "effective date of the standard" (section 317(c) (2)) has no effect on the rule's costs, since the trigger date for new source status is the date of proposal.  In addition, the EPA has taken action to assure that sources under development are not subject to the final standard of performance.  See preamble section III.J.  The EPA also structured the proposed and final standard to avoid more costly alternatives, but rejected the 'business as usual' option as not reasonably fulfilling the requirement of section 111 (a) to base standards on the performance of the best system of emission reduction adequately demonstrated.  

The EPA's modeling, conducted using the Integrated Planning Model (IPM), as well as modeling conducted by the U.S. Energy Information Administration (EIA) showed that new generating capacity built through the period of analysis would be in compliance with the standard even in the baseline scenario, and as a result, the rule would not lead to any changes in behavior. This finding held true even under a number of alternative scenarios. As a result, the EPA projected there would be negligible costs, benefits, energy impacts (including changes to electricity prices), employment impacts, or economic impacts associated with the rule in the period of analysis. (See Chapter 4 of the RIA.) In addition, the Regulatory Impact Analysis for the rule included several illustrative analyses, examining the costs of the rule under a range of natural gas prices and the cost associated with building a coal plant with CCS. (See Chapter 5 of the RIA.) This analysis found that, while there are additional costs to building a coal-fired power plant with CCS, there are also climate and human health benefits, as well as potential for revenue from enhanced oil recovery. 

The commenter is not correct that the final standards of performance are without benefits.  It is correct that the base case modeling the EPA performed for this rule projects that, even in the absence of this action, new fossil fuel  -  fired capacity constructed through 2022 and the years following will most likely be NGCC capacity that complies with the final standards.  This is due to current and projected economic market conditions.  See generally RIA chapter 4.  Nonetheless, there could be circumstances where new coal-fired capacity is built  -  commenters to EPA's initial proposal maintained adamantly that this was a possibility (although no specific examples have as yet been provided).  In that event, EPA conducted further analysis which shows that there would be net quantified monetary benefits to society in the form of reduced CO2 emissions and secondary fine PM emissions from SCPC facilities (due to reduced SO2 emissions).  See RIA chapter 5.2.  That is, for each new SCPC facility that would be constructed, the cost of meeting a 1400 lb/MWh-gross standard is more than offset by the monetized benefits of the CO2 and secondary fine PM. This analysis does not quantify other benefits of the standard.  The standard provides certainty for new plants (see, for example, the AEP FEED study associated with the Mountaineer project, where the company states that it was abandoning the project due to regulatory uncertainty), and a means to enable carbon control technology that will allow future coal  -  fired capacity in a reduced carbon economy.  The commenters are also correct as a matter of law that some type of section 111 (b) standard is a legal condition precedent to section 111 (d) guidelines for existing sources, but this rule has positive benefits with or without consideration of that additional factor.   Power plants are the biggest emitters of carbon pollution. While companies building power plants today are already making cleaner generation choices, such as natural gas combined cycle or coal with CCS, the proposed rule would lock in a lower carbon future and make sure this progress continues.  The plants built under this standard would be cleaner than the average coal unit operating today  -  which emits over 4 million metric tonnes of CO2 a year. By comparison, a new natural gas plant would emit 1.7 million tonnes a year, or about 2.3 million metric tonnes less; and a new, modern coal unit would emit no more than 3 million tonnes per year, or about 1 million tonnes less. In 2009, the EPA Administrator found that elevated concentrations of greenhouse gases in the atmosphere may reasonably be anticipated both to endanger public health and to endanger public welfare. It is these adverse impacts that make it necessary for the EPA to regulate GHGs from EGU sources. This statement of the purpose of the regulation can be found in the Regulatory Impact Analysis.

The comment (9776) that the promulgated NSPS will lead to increase CH4 emissions due to increased use of natural gas has no basis.  New natural gas capacity is being added for reasons unrelated to this standard of performance.  See RIA chapter 4.  The commenter also evidently assumes CH4 emissions associated with natural gas production and transport are uncontrollable, which the EPA does not believe to be the case.

The EPA has addressed the achievability of final standards for new steam generating units  -  including those using varying fuel types  -  in preamble section V.J and also in a Technical Support Document "Achievability of the Standard for Newly Constructed Steam Generating EGUs"  -  available in the rulemaking docket.
Commenter 8024 states a new Harvard study quantitatively estimates the spatial distribution of anthropogenic methane sources in the United States by combining comprehensive atmospheric methane observations, extensive spatial datasets, and a high-resolution atmospheric transport model. Results show that current inventories from the US Environmental Protection Agency (EPA) and the Emissions Database for Global Atmospheric Research underestimate methane emissions nationally by a factor of ~1.5 and ~1.7, respectively. These results cast doubt on the US EPA's recent decision to downscale its estimate of national natural gas emissions by 25-30%. Overall, we conclude that methane emissions associated with both the animal husbandry and fossil fuel industries have larger greenhouse gas impacts than indicated by existing inventories.
Some commenters stated that EPA estimates of methane from natural gas systems are underestimates. Some commenters cited studies showing higher emissions than EPA estimates. EPA's emissions estimates are based on the best data available at the time of their development. It is EPA's standard process to update its estimates in the annual Inventory of U.S. Greenhouse Gas Emissions and Sinks (GHG Inventory) when new and improved data are available which would improve emissions calculations. Every year, EPA reviews new data and conducts an extensive annual multi-phase process including expert review during GHG Inventory development and public review before finalization of the Inventory.  In recent years, the natural gas sector has experienced significant growth and changes in industry practices.  Emissions profiles from industry practices such as hydraulic fracturing and liquids unloading have changed significantly, and only recently have data become available to improve our understanding of emissions for these sources.   EPA's estimates take into account differences in production emissions for conventional versus unconventional practices.  For example, EPA calculates national emissions from gas well completions and workovers with hydraulic fracturing using data on over 25,000 of these events reported to EPA's Greenhouse Gas Reporting Program (GHGRP).  As expected, incorporating newly available data resulted in changes to emissions estimates for the oil and gas sector overall.   

EPA is aware of studies calculating methane emissions that differ from EPA's estimates.  EPA continues to refine the emission estimates in the GHG Inventory to reflect the most robust and up to date information available.  Substantial amounts of new information on the oil and gas sector will become available in the coming years from a number of channels, including EPA's GHGRP, and research studies by government, academic, and industry researchers, and industry organizations.  In addition, the actions in the White House methane strategy, which target both bottom-up and top-down measurement approaches, will improve the overall level of confidence in methane emissions data.  EPA looks forward to reviewing new information and data as they become available for potential incorporation in the GHG Inventory. 

EPA does not officially calculate a leak rate for the natural gas industry. Through our annual, national-level Inventory of U.S. Greenhouse Gas Emissions and Sinks, we provide an estimate of total greenhouse gas emissions from the oil and natural gas sector. This estimate includes process emissions like vented and fugitive methane emissions from over 100 activities and equipment types that generate emissions in the natural gas industry, from drilling and production, through processing and transmission, to distribution. Others have developed leakage rate estimates using emissions estimates from EPA's national GHG Inventory, along with data from other sources, such as oil or gas production data from EIA.
Comments on IPM
Commenter 9686 states a major issue with the IPM model is its limited time frame: it cannot run out to 2040 as can EIA NEMS. The time frame between 2020 and 2040 is the most important for the EPA NSPS rule. Commenter states it's obvious from this analysis by EIA that the major effects of EPA policies are significant beyond 2020. The RIA is deficient because of the IPM limitations.
Commenter 10098 states through the application of various assumptions, EPA miscalculates that the cost differential between natural gas and coal generation will drive future construction of EGUs subject to the proposed rule toward natural gas units for the foreseeable future. In other words, EPA assumes that beyond the next NSPS review cycle - and even beyond 2030 - coal-fired EGUs are unlikely to be constructed due to generation economics, and, therefore, the proposal will have no costs or benefits at all. 79 Fed. Reg. at 1433; RIA at 5-1. EPA then uses this conclusion as an excuse for not performing a full cost-benefit and economic impact analyses. EPA's approach is both fundamentally flawed and incorrect, and EPA's decision to not engage in a substantive cost benefit analysis or economic impact analysis is arbitrary and capricious.
Commenter 3176 states the proposed rule effectively bans traditional coal-fired generating technology as a future supply option, despite the fact that this base-load technology has provided reliable, cost-effective electricity to consumers in Alabama, and nationally, for many decades. In so doing, the proposed rule stands to weaken the country's generation portfolio and significantly impact the future cost of electricity.
Commenter 8743 states the examples of case law and the rulemaking precedent U.S. EPA cites in section VI.H of the Proposed Rule suffer from the same problem: the technologies applied to the source categories discussed control pollutants that can have local or national ambient air quality or distinct air quality-related value impacts. U.S.
Commenter 10555 states the IPM model making the required economic forecast that natural gas-fired EGUs will be the facilities of choice until at least 2020 is insufficiently robust to capture EIA's expectation of price increases starting just 10 years from now. The EPA's arbitrary examination of the costs of the rule only through 2020 is a significant error, in that, among other things, electric generation facilities typically have life spans of 40 years or more. An appropriate assessment of the cost of the policy would use a similar time span. Equally troubling is EPA's reliance upon a single point forecast of projected new generation using coal and natural gas prices that run out to only 2020. It is impossible to say that new coal-fired generation is not going to be cost effective in the future based on a single modeled outcome or without considering potential coal and gas prices in the post-2020 time period. Commenter states that, moreover, the current low price of natural gas is attributed to an increased supply which is a result of the recent technological advances in hydrological fracturing (fracking) that has allowed the natural gas industry to recover gas from wells long considered unviable.
Commenter 7977 states the proposed rule relies on results from an Integrated Planning Model (IPM) that projects an abundance of natural gas and a continued decline in natural gas prices. The Commenter questions whether the IPM model accounted for the effects on natural gas prices and availability resulting from future EPA rulemaking for the production and processing of natural gas (such as fracturing or "fracking" rules) or the impacts of natural gas exports.
Commenter 9765 states the EPA asserts in the Regulatory Impact Analysis (RIA) "that the Proposed Rule will result in negligible CO2 emission changes, energy impacts, quantified benefits, costs, and economic impacts by 2022." The EPA bases this conclusion on economic modeling and analysis that demonstrates that even with the Proposed Rule, existing and anticipated economic conditions will lead power producers to choose new generation technologies that meet the proposed standard without the need for additional controls. It appears from reading the plain language of the RIA that the EPA does not need to propose a rule to influence CO2 emissions from new sources. Yet, the additional costs created by the rule are acceptable to the EPA, including costs of record keeping, source monitoring, and administrative overhead. The EPA should clarify how such costs are justified if they will not yield tangible results. Commenter states while the EPA relied on the use of IPM in past actions, it did not take appropriate steps to ensure the underlying cost assumptions were valid for the Proposed Rule. Specifically, the EPA provides no information in the record showing that the assumptions for the performance and cost of GHG pollution controls input into the model were based on actual operating data. Nor does the EPA show that the assumptions were modeled based on empirical data from projects of the appropriate industrial scale. Furthermore, the assumptions the EPA made regarding the cost, performance, and reliability of carbon capture and storage are highly suspect. The EPA admitted in the RIA that carbon capture technology is not proven for large-scale facilities. "Carbon capture technology has been successfully applied since 1930 on several smaller scale industrial facilities and is currently in the demonstration phase for power sector applications. There are currently larger-scale projects under construction or in the advanced planning stages." The EPA must address the accuracy and representativeness of cost, reliability, and performance data used in the model that came from the projects that are either under construction or in advanced planning. In the absence of representative empirical data, the EPA should consider delaying any proposal for coal-fired EGUs until such data is collected, quality assured, and made available for peer review and comment.
Commenter 10618 states the IPM model also uses outdated capital cost inputs associated with new generation sources. 
Commenter 10119 states CO2 emissions from existing simple cycle plants totaled 22,679,318 short tons (nearly 20.6 million metric tons) in 2011 alone. Moreover, simple cycle emissions may well increase over the next eight years. EPA's own IPM model runs show that new simple cycle combustion turbine generation is expected to grow from 1,903 MW in 2016 to 5,052 MW by 2025, and  EPA does not quantify the potential emissions associated with this new generation, they may be expected to be significant given that capacity is anticipated to more than double.
The IPM model is a PROPRIETARY model that should not be used for policy analysis. The model development and application is captive to EPA funders and the EPA agenda. The public must have complete, unfettered access to any model used for policy as is required by the Information Quality Act (IQA). The EIA-NEMS model meets the IQA criteria, the IPM model does not. 
The EPA disagrees with these comments. IPM is a multi-regional, dynamic, deterministic linear programming model of the U.S. electric power sector. It provides forecasts of least cost capacity expansion, electricity dispatch, and emission control strategies while meeting energy demand and environmental, transmission, dispatch, and reliability constraints. The EPA has used IPM for over two decades to better understand power sector behavior under future business as usual conditions and evaluate the economic and emission impacts of prospective environmental policies. The model is designed to reflect electricity markets as accurately as possible. The EPA uses the best available information from utilities, industry experts, gas and coal market experts, financial institutions, and government statistics as the basis for the detailed power sector modeling in IPM.  The model documentation provides additional information on the assumptions discussed here as well as all other model assumptions and inputs. 

Although the Agency typically focuses on broad system effects when assessing the economic impacts of a particular policy, the EPA's application of IPM includes a detailed and sophisticated regional representation of key power sector variables and its organization.  When considering which new units are most cost effective to build and operate, the model considers the relative economics of various technologies based on a wide spectrum of current and future considerations, including capital costs, operation and maintenance costs, fuel costs, utility sector regulations, and emission profiles.  The capital costs for new units account for regional differences in labor, material, and construction costs. These regional cost differentiation factors were developed based on data and assumptions used in the EIA's AEO 2013.

As part of IPM's assessment of the relative economic value of building a new power plant, the model incorporates a detailed representation of the fossil-fuel supply system that is used to forecast equilibrium fuel prices, a key component of new power plant economics.  The model includes an endogenous representation of the North American natural gas supply system through a natural gas module that reflects full supply/demand equilibrium of the North American gas market.  This module consists of 118 supply, demand, and storage nodes, 15 liquefied natural gas regasification facility locations and three LNG export facility locations that are tied together by a series of linkages (i.e., pipelines) that represent the North American natural gas transmission and distribution network.

IPM also endogenously models the coal supply and demand system throughout the continental U.S., and reflects non-power sector demand and imports/exports.  IPM reflects 36 coal supply regions, 465 coal supply curves for each of nine years, 14 coal sulfur grades, and the coal transport network, which consists of 4,947 linkages representing the costs of transporting coal via rail, barge, and truck and conveyer linkages connecting 41 regions with 575 individual coal-fired generating stations.  The coal supply curves and the transport network costs used in IPM are publicly available, and were developed during a thorough bottom-up, mine-by-mine approach that depicts the coal choices and associated supply costs that power plants will face over the modeling time horizon.  The IPM documentation outlines the methods and data used to quantify the economically recoverable coal reserves, characterize their cost, and build the 84 coal supply curves.  These curves have been independently reviewed by industry experts and have been made available for public review on several occasions over the past two years during other rulemaking processes.  

The EPA has used IPM extensively over the past two decades to analyze options for reducing power sector emissions. The model has been used to forecast the costs, emission changes, and power sector impacts for the Clean Air Interstate Rule (CAIR), Cross-State Air Pollution Rule (CSAPR), the Mercury and Air Toxics Standards (MATS), and the proposed GHG emission guidelines for existing source EGUs.   Recently IPM has also been used to estimate the air pollution reductions and power sector impacts of water and waste regulations affecting EGUs, including Cooling Water Intakes (316(b)) Rule, Disposal of Coal Combustion Residuals from Electric Utilities (CCR) and Steam Electric Effluent Limitation Guidelines (ELG).

The model undergoes periodic formal peer review, which includes separate expert panels for both the model itself and the EPA's key modeling input assumptions.  The rulemaking process also provides opportunity for expert review and comment by stakeholders, including owners and operators of the electricity sector that is represented by the model, public interest groups, and other developers of U.S. electricity sector models.  The EPA is required to respond to significant comments submitted regarding the inputs used in IPM, its structure, and application.  The feedback that the Agency receives provides a detailed check for key input assumptions, model representation, and modeling results. IPM has received extensive review by energy and environmental modeling experts in a variety of contexts.  For example, from the mid-1990s through 2011 the Science Advisory Board reviewed IPM as part of the Clean Air Act (CAA) Amendments Section 812 studies of the CAA costs and benefits that are periodically conducted.   The model has also undergone considerable interagency scrutiny when it has been used to conduct over one dozen legislative analyses performed at Congress' request over the past decade.  In addition, Regional Planning Organizations throughout the U.S. have extensively examined IPM as a key element in the state implementation plan (SIP) process for achieving the National Ambient Air Quality Standards.  The Agency has also used the model in a number of comparative modeling exercises sponsored by Stanford University's Energy Modeling Forum over the past 15 years.

IPM has also been employed by state partnerships (e.g., the Regional Greenhouse Gas Initiative (RGGI), the Western Regional Air Partnership, Ozone Transport Assessment Group), other federal and state agencies, environmental groups, and industry, all of whom subject the model to their own review procedures. States have also used the model extensively to inform issues related to ozone in the northeastern U.S.  This groundbreaking work set the stage for the NOx SIP call, which has helped reduce summer nitrogen oxide (NOx) emissions and the formation of ozone in densely populated areas in the northeast.  

See full documentation of the model, which is available in the docket.  This documentation includes information on model horizon (2050) and capital cost assumptions, which EPA believes are reasonable.

Further Commenter 9765 claimed that the assumptions the EPA made regarding the cost, performance, and reliability of carbon capture and storage are highly suspect. The EPA disagrees, the cost estimates for CCS reflect the latest vendor quotes for the Shell Cansolv technology, the technology used in full commercial application (successfully) at the Boundary Dam facility. Sequestration cost estimates are based on costs developed in the robust Class VI rulemaking proceeding.  See generally preamble section V.I. 2 and .5.
Base year
Commenter 5731 supports the use of 2005 as the base year for level of control, explaining that Year 2005 is a national emissions inventory (NEI) year for which states were required to submit full emissions inventories pursuant to the Air Emissions Reporting Requirements Rule. Year 2005 is also the best representation of the electric generation market, energy supply and demand, before the onset of the economic recession in 2008.
The EPA thanks the commenter for this observation.
8-yr forecast period too short
Commenter 10095 states, acknowledging Section 111(b) requires NSPS be review every eight years, that EPA's limiting its evaluation period to eight years is flawed because the new source performance standards will not cease to exist after eight years. Commenter explains that, to commenter's knowledge, EPA has never decreased the stringency of or removed new source performance standards after a review period and the cost-benefit evaluation should be broadened to more accurately reflect the utilities' analysis periods for electric generating asset decisions, which are commonly 20 to 30 years in length, to ensure the best long-term decision for customers.
Commenters 10618 and 7977 state EPA erroneously concluded that the proposed rule will have negligible costs or impacts on society based on the flawed premise that no new coal plants will be built absent this rule, explaining that this is inconsistent with EIA scenarios showing new unplanned coal additions prior to 2020 and significant additions of new coal generation under certain model scenarios in later years. Commenter adds that EPA arbitrarily examined the costs of the rule only through 2022, based on the eight-year review cycle for Section 111(b) regulations. This is a significant omission in the analysis in that truncation of the regulatory period in question hides the true potential cost of the regulation. Furthermore, even with an eight-year regulatory review cycle, this regulation is likely to set a de facto emission rate limit for future review periods. Commenter explains that new baseload generating capacity takes a number of years to plan, permit, engineer and construct. Some generating assets coming online after 2022 will have to be planned and permitted prior to 2022, and thus will be subject to the proposed standard. EPA's argument that reviewing the NSPS within eight years renders post-2022 analysis irrelevant is incorrect. Truncating the analysis based on a presumed future regulation is also at odds with previous EPA assertions that it will not speculate on future rulemakings in its modeling efforts. EPA states in the documentation for the IPM results that the base case represents "a projection of electricity sector activity that takes into account only those Federal and state air emission laws and regulations whose provisions were either in effect or enacted and clearly delineated at the time the base case was finalized." 
Commenter 10618 continues that EPA's reliance upon a single forecast of projected new generation using coal and natural gas prices that run out to only 2022 is troubling, stating that it is impossible to say that new coal- fired generation is not going to be cost-effective in the future based on a single modeled outcome or without considering potential coal and gas prices in the post-2022 time period. Other scenarios recently developed by EIA indicate that, under varying market conditions projected in the past, some new generation may be built prior to 2022 (~300 MW) and many other new coal units may in fact be built post-2022. EPA did not examine any additional combination of scenarios beyond those previously published. As an example, under a scenario where natural gas resources are less economically developed and the Climate Uncertainty Adder (to be discussed later) is removed dramatically more coal builds would occur.
Commenter 10618 states EPA's RIA states on page 4-31 that: "The natural gas market in the United States has historically experienced significant price volatility from year to year..." Commenter agrees and notes that domestic and international natural gas prices have historically experienced seasonal and annual volatility that resulted in significant spikes for periods of time. The extreme volatility in natural gas pricing should lead to the logical conclusion that structuring the cost benefit/analysis for this rule on a single gas forecast extending through only 2022, with prices near the lowest levels of the past decade, is not a rational or prudent approach. Instead, multiple natural gas price trajectories should be examined in conjunction with the cost analysis for the rule.
Commenter 10046 states that EPA opines that its conclusion that no new coal units will be built "is robust beyond the analysis period (past 2030 in both [U.S. Energy Information Administration] and EPA baseline modeling projections) and across a wide range of alternative potential market, technical, and regulatory scenarios that influence power sector investment decisions." In other words, EPA believes there are no plausible circumstances under which new coal units might get built, not only under the traditional eight-year review period for NSPS, but also well beyond that time (in fact, for at least twice as long - at least sixteen years). EPA opines that its projection will remain true even if gas prices rise significantly under a worst-case gas supply scenario. And EPA maintains that its projected results will hold even if power companies adopt a No GHG Concern approach. The Congressional Research Service (CRS) reviewed EPA's RIA conclusions and agreed with them. CRS assessed the state of the power market, finding: The net result is that coal is simply not competitive with natural gas in most areas of the country when power producers consider new generation facilities in current and foreseeable conditions. EPA's analysis finds that natural gas would need to triple in price for coal to be competitive with it, even without the potential cost of this rule. . . . This rule will tilt the playing field even further against new coal-fired generation, but the field was already tilted far in that direction. Based on this assessment, CRS concluded: Since the early 1990s, new coal-fired plants have accounted for less than 10% of new power-generating capacity. In these conditions, the electric power industry is likely to continue doing what it has already been doing for two decades: building gas-fired plants (or relying on renewable sources) when it needs new capacity. Since there is little doubt that no or very few new coal units will be built for a number of years, it is not reasonable for EPA to rely, like it did in the motor vehicle rule, on emissions from existing EGUs as a reasonable surrogate for projected future emissions from the coal-fired source category for which EPA has to make a cause-or-contribute-significantly finding. Thus, we can readily dismiss the relevance of EPA's contention that affected EGUs emit almost one-third of all U.S. GHGs and comprise by far the largest source category of GHG emissions. 
Commenters 10046 and 10555 state that EPA's position is that new coal units contribute significantly to climate change, even though EPA specifically concludes that there will not be any built which would be subject to this rule. In contrast to EPA's projection, DOE's Annual Energy Outlook (AEO) modeling in the RIA indicates that 0.3 GW of new CCS coal-fired capacity will be built by 2020. Commenter contends that EPA is obligated to make a very specific determination that this amount of emissions from this number of new sources plausibly contributes significantly to climate change. EPA's disclaimer that it is not necessary for the EPA to decide whether it must identify a specific threshold for the amount of emissions from a source category constitutes a significant contribution simply will not do when potential emissions from new sources in a source category may be 0-900,000 TPY.
Also, commenter 10046 states EPA estimates that existing coal-fired units emit 1,722,700,000 TPY of CO2. Thus, at 900,000 TPY, the new unit projected by DOE would emit something less than 0.05% of the total GHG emissions from the existing source category. EPA also estimates that there was about 343,757 GW of coal-fired capacity in the country in 2011. The addition of 0.3 GW of new coal-fired capacity would amount to 0.1% of the amount of existing coal-fired capacity in the source category. EPA cannot rationally conclude that these emission amounts could contribute significantly to climate change, or even provide EPA with a rational basis for regulating GHG emissions from new coal units. Notably, according to EPA, new coal units, if any, are already expected to install at least partial CCS and comply with EPA's proposed emissions standard (although DOE's CCS-demonstration requirements will likely require more). That puts any new coal plant emissions limits on par with new gas combined cycle (1,100 lbs. CO2/MWh vs. 1,000 lbs. CO2/MWh, for coal and gas respectively). Hence, the new coal source, or sources, if any, that EPA believes will contribute significantly to climate change would emit at a rate virtually the same as the gas combined cycle units EPA declares to be a low-GHG-emitting fuel powered by a low-emitting technology. Thus, EPA would have to conclude that the possibility of a tiny number of new low-emitting technology units supports its conclusion that new coal plants contribute significantly to climate change.
Commenter 10046 states EPA also traditionally uses its assessment of the expected growth rate of a source category (or a part of that source category) and the level of future emissions to exclude from regulation parts of source categories where no growth is expected or future emissions levels will be small. In setting the Beverage Can Surface Coating Industry NSPS, EPA originally proposed to regulate both two-piece and three-piece beverage can surface coating operations. EPA, however, changed its mind and excluded the three-piece can industry segment from regulation, noting: Six commenters said that three-piece beverage cans were being phased out, with an estimated 1985 [two years hence] production between 0.5 billion and 1.5 billion cans, and should be excluded from the standards. As a result of these comments, EPA analyzed previous projections and determined that estimated demands for three-piece can capacity in 1985 would be about 50 percent of available capacity. Consequently, three-piece cans are excluded from the promulgated standards. 
Commenter 10555 states EPA's modeling is insufficiently robust to capture future price fluctuations across fuel sources. Further, the EPA's examination of costs only through 2022 is problematic given that EGUs typically have life spans of 40 years or more. Commenter states that an appropriate assessment of costs would use a similar time span. Finally, the EPA's reliance on a single point forecast of projected new generation using coal and natural gas through 2022 is equally problematic. Commenter concludes that it is impossible to say that new coal-fired generation is going to be cost prohibitive in the future based on a single modeled outcome that does not adequately consider post-2022 coal and gas prices, or account for the additional transmission and other infrastructure costs associated with alternative energy sources.
CAA Section 111(b) requires that the new source performance standards (NSPS) be reviewed, and potentially revised, every eight years. The EPA will (indeed, must) consider the available data at this time. For this reason, it is appropriate to consider the impacts of the regulation on EGU's built in that timeframe. 
The EPA's modeling, conducted using the Integrated Planning Model (IPM), as well as modeling conducted by the U.S. Energy Information Administration (EIA) showed that new generating capacity built through the period of analysis would be in compliance with the standard even in the baseline scenario, and as a result, the rule would not lead to behavior changes. The EPA's finding of no new, unplanned conventional coal-fired capacity is robust beyond the analysis period (past 2030 in both U.S. Energy Information Administration  -  EIA  -  and EPA baseline modeling projections) and across a wide range of alternative potential market, technical, and regulatory scenarios that influence power sector investment decisions. (See Chapter 4 of the RIA.) The Regulatory Impact Analysis for the rule includes several illustrative analyses, examining the costs of the rule under a range of natural gas prices and the cost associated with building a coal plant with CCS. (See Chapter 5 of the RIA.)
In 2009, the EPA Administrator found that elevated concentrations of greenhouse gases in the atmosphere may reasonably be anticipated both to endanger public health and to endanger public welfare. Based on emission inventories, EGUs are the largest stationary source of GHG emissions in the U.S. The analysis in this regulation does not impact that conclusion.
3% surcharge to coal-fired plans biases outcome and handle cost impact of current permitting environment as a separate accounting charge
Commenters 9666, 10554, and 10618 state escalation in project costs can be driven by delays due to litigation and the need to study numerous alternatives, and EPA proposes to quantify the cost impact of these delays by adding a 3% surcharge to the capital cost of a coal-fired power plant. Commenter posits that arbitrarily assigning a cost penalty for CO2 - in an analysis whose objective is to determine the cost to control CO2 - necessarily biases outcome and states that the political climate encountered in permitting new coal-fired power plants is indeed hostile and higher costs are incurred - but these are non-technical concerns.(see added remarks) Commenter closes that the cost impact of the present permitting environment is real but should be handled as a separate accounting charge, similar to Allowance for Funds Used During Construction, explaining that this charge is not technology-based and should not bias the outcome of a cost study. Commenter 10554 notes that the effect on the levelized cost of energy (LCOE) for Super Critical Pulverized Coal (SCPC) units arise from $81/MWh without CCS to $92/MWh with the 3% CUA. Commenter 10618 explains that because this proposed NSPS removes much of the uncertainty regarding GHG emission reduction requirements by setting a standard, this penalty should be reduced or removed altogether in the modeling of the reference case for comparison purposes.
Commenter10618 states the premise behind the CUA is to represent the fact that risks associated with future climate policy are likely to impact choices for new generation and that while in practice the carbon policy risk does factor into planning decisions, the CUA is being improperly used. For example, many utilities use a carbon price in their planning decisions, however this price is typically back loaded within the planning period given policy uncertainty and the regulatory development period necessary for such a variable to have practical effect. Therefore, the 3% WACC adder as currently employed is artificially high.
Commenter 10618 states carbon risk should be accounted for outside of a LCOE comparison, and thus the CUA should not be included as part of LCOE. When modeling the electric sector as a whole, it may be appropriate to characterize carbon risk, but to provide a true "apples to apples" LCOE comparison, the CUA should never be included. A number of external factors play into generation investment decisions, which are also not "monetized" within the LCOE. Removing the CUA adder from the LCOE would dramatically reduce the breakeven natural gas price necessary to favor new coal. Commenter concludes that any future analysis by either EPA or EIA should not use a CUA in evaluation of technology
Commenter 10618 states the differences in levelized cost between NGCC and SCPC units is dramatically overstated and is particularly compounded by the use of a Climate Uncertainty Adder (CUA) within several of the comparisons, as discussed later in the comments. Therefore, EPA's statement that "it is only when natural gas prices reach $10.94/MMBtu on a levelized basis (in 2011 dollars) that new coal-fired generation without CCS becomes competitive in terms of its cost of electricity" 337 (RIA at 5-48) is patently false. Underestimation of NGCC capital and operational costs, overstatement of NGCC operational hours, and overstated operational costs for new coal units make the breakeven number significantly lower. This is demonstrated by the EIA analysis, which identifies new coal as being built in various sensitivity cases; even though EPA states that "none of the EPA sensitivities or AEO2013 scenarios approach this natural gas price level on either a forward looking 20-year levelized price basis or on an average annual price basis at any point during the analysis period." These new coal builds occur within the model due to more accurate input data being used and the model correctly calculating the effect cost of new generation based on actual operation. 
See preamble section I.2. and Chapter 4.5.3 of the RIA for a full discussion of the use and applicability of a Climate Uncertainty Adder (CUA).  This use of a CUA is appropriate, and is consistent with the industry's current planning and evaluation framework.  (Even UARG consultant Mr. Cihanowicz stated with respect to the CUA that "the impact of the present permitting environment is real" although urged that that cost "should be handled as a separate accounting charge".  Comment 9666 App. 1 p. 5. ) While omitting the CUA is inconsistent with an analysis considering how project characteristics and market conditions would lead a developer or utility to select a certain project, we evaluate the LCOE with and without the CUA and note that it does not have an impact on our findings.  It is appropriate to account for the CUA when forecasting the behavior of private actors in choosing between different technologies based on expected future costs, as this represents a potential cost investors must consider. In the analysis in Chapter 5 of the RIA, the CUA is not included when comparing the costs to the potential benefits associated with emission reductions. When comparing the difference in costs of illustrative new units after construction, such as in the analysis of the social costs of these technologies (i.e., the private cost plus the cost associated with their emissions), the CUA is not included. 
 In addition, all LCOE estimates of coal-fired facilities with CCS are presented without the CUA, to represent the reduced CO2 liability associated with such technologies.  RIA section 4.5.3. Thus, this issue has minimal bearing on the key decisions in this rulemaking, since CUA is not reflected in the cost estimates for the BSER, and the decision that SCPC alone is not BSER is not based on cost of SCPC, but rather reflects the fact that there is a better-performing, adequately demonstrated technology.  See preamble section V.P.2.  
Capital recovery factor 
Commenter 9666 states using these capital recovery factors with the capital cost presented in the 2013 RIA does not reproduce the annual payment cited by EPA. (Specifically, the levelized annual payment for capital cost (in terms of $/MWh) does not match that illustrated in Figure 5-3 of the RIA for the case of SCPC w/o the CUA. Using a capital cost of $2,452/kW, gross generating capacity of 580.3 MW, capacity factor of 85%, and a capital recovery factor of 10.23%, the levelized annual capital payment is determined to be $33.7/MWh (2011 basis). Figure 5-3 suggests an annual capital cost of about $38/MWh.) The 2013 RIA results can be approximated using capital recovery factors recommended in the most recent Department of Energy/National Energy Technology Laboratory cost evaluation of SCPC and NGCC. Commenter closes that these values of capital recovery - 11.6% and 12.4% for NGCC and SCPC, respectively, when used in the levelized cost of electricity calculation closely replicate the results in 2013 EIA Figure 5-3.
 The CCS costing spreadsheets used by the EPA are included in the docket to this final rule.
Consider variability in natural gas quality
Commenter 9770 states the EPA has not taken into account the effect on the emissions limit of the quality of the natural gas provided by suppliers and pipeline companies to the generating units. Commenter explains that depending on season and availability, the natural gas quality can be degraded by mixtures with propane, butane, air mixtures or other petroleum gases that will increase the emission outputs from the plants without any possible control technology. Commenter contends this is a serious oversight in the proposed rule that requires the agency to develop criterion for natural gas supplies.
 
EPA disagrees. There is no reason to expect that future natural gas quality for electric generation will be degraded from the historical qualities that are used in modeling projections.  This comment does not give any reason to reexamine this issue.
Use additional and more robust scenarios that do not include CUA in the baseline
Commenter 8925 states regulatory impact analyses typically start with a reference case that assumes only regulations that are in place and then compare that to a case which adds the new, proposed regulation.  Commenter continues that in this instance, EPA starts with an EIA reference case that is not based solely upon current regulations, but instead, includes a cost adder on coal designed to reflect future policy uncertainty.  As EPA notes in its proposal: 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 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 CO2 emissions in power sector resource planning. The EIA calculated the Climate Uncertainty Adjustment (CUA) by adjusting the cost of conventional coal without CCS upward until no new (unplanned) coal was deployed in its reference case.  EIA's intent in developing its reference case was to mimic company decision making given regulatory and legislative uncertainty about climate policy. Including the CUA in EIA's reference case is an exception to their usual approach of assuming only existing regulations, but for the purpose of creating a projection of the future that reflects industry realities, there is some rationale for doing so. For a regulatory cost analysis, it is not appropriate.  Commenter urges EPA to consider additional and more robust scenarios that do not include the CUA in the baseline. 
Commenter 8925 continues that in RIA Table 5-3 and the accompanying text, EPA makes the argument that conventional coal will not be deployed across a wide range of EIA's scenarios from its AEO 2013.  That is a consistent finding across EIA's scenarios for 2020, assuming the range of natural gas prices examined.  Also note that 4 of the 5 cases presented in the table assumed the CUA.  The one case that EPA presents that does not include the CUA, the "No GHG Concern" case, also has no new builds of coal through 2022, but does have 17GW of unplanned new coal additions between 2014 and 2040.  If EIA were to run a case without the CUA and with EIA's higher gas price scenario, conventional coal additions would begin in 2023 and rise to 40GW/year of new conventional coal additions by 2040. Commenter also notes that other modeling groups also project future scenarios with significant additions of new coal, citing, for example, a forthcoming study conducted by the Stanford Energy Modeling Forum focused on the U.S.  The study's overview paper shows scenarios of CO2 emissions from the power sector that continue to increase (up to 15%) from 2015 out to 2040 under an assumption of no specific climate polices or regulation. This is a robust finding that is supported by the seven US modeling groups participating in the study including models from Research Triangle Institute/EPA, Pacific Northwest National Laboratory, Environment Canada, MIT, NERA and EPRI. Given these results from the principal modeling groups in the US, commenter strongly encourage EPA to reconsider its reference case in the RIA and remove any assumptions that impose restrictions on CO2 and hence on new coal unit construction in the future when trying to assess the cost of this regulatory proposal.  EPRI encourages EPA to examine more scenarios that do not include the CUA (see previous comments on issues associated with CUA as the reference case) to explore both the robustness of this conclusion and the need for a more detailed regulatory impacts analysis. Commenter's recommendation is based on NEMS analyses as well as assessments such as those conducted under the Stanford Energy Modeling Forum Study 24.13 Federal Register. Vol 79. No.5, p. 1477.
Commenter 10046 states the CCS cost adder is very large in absolute terms. The specific impacts of EPA's proposed $18/MWh CCS cost adder can be readily seen by employing a neutral cost baseline between coal and gas plants to eliminate current non-NSPS market impacts. Because gas plants cost $59/MWh, we assume that both new gas and new coal plants cost $59/MWh. From this perspective, the impact of the $18/MWh CCS cost adder increases the cost of a new coal plant by 30 percent on its own against the cost of a new gas plant. That is a very substantial increase, and it does not seem plausible to suppose that a cost increase of 30 percent added to new coal plants would make them economically viable when compared to new gas plants. Commenter concludes that this analysis indicates that the CCS cost adder alone would have a very significant adverse impact on the economic viability of new coal plants.
See response to Comment 3.2-14 above.  
Broaden CUA to all generation types that emit CO2
Commenter 7977 states the CUA (climate uncertainty adder) should be applied to all generation types that emit CO2, including partial CCS and all natural gas generating technology. Commenter adds the use of the 3 percent CUA is arbitrary and likely quite low.
Commenter 10618 states within generation planning processes, carbon policy assumptions are typically applied across all fossil fuel choices and are coupled with a market response to energy pricing, if modeled within an integrated electric sector and/or economy-wide model. Therefore, inclusion of the CUA only with respect new coal does not provided the appropriate perspective or feedback on true carbon risk as it would suggest there is no carbon risk associated with other fossil fuels, namely natural gas.
Commenter 9407 states EPA's conclusion that coal cannot complete with natural gas for new electric generation is based on an arbitrary set of presumptions. Commenter contends that EPA also inserts a "climate uncertainty adder" that serves to drive up the cost of coal-fired EGUs but not NGCC EGUs. The insertion of any "climate uncertainty" involves deriving at nothing more than as arbitrary number, reflecting nothing technical in nature. Commenter 9407 continues that for coal-fired EGU capital costs, EPA disregarded the figure in the most recent 2013 DOE study that presumably would reflect the best estimate and instead used a higher figure derived from an earlier DOE study. These and other factors used in EPA cost methodology serve to increase the projected costs coal-fired EGUs. By using different assumptions, all within the uncertainty ranges in the DOE studies, coal-fired EGUs can compete with regarding future generation on a cost basis.
Commenter 10555 states energy market projections are subject to much uncertainty, explaining that many of the events that shape energy markets are random and cannot be anticipated. In addition, future developments in technologies, demographics, and resources cannot be foreseen with certainty. Commenter provides a graphic showing the price volatility of natural gas since 2000. 
See response to comment 14 above regarding the CUA. Regarding the volatility of natural gas prices, in Chapter 5 of the RIA, the EPA presents an analysis of the potential costs and benefits of the standards under a range of natural gas prices. It is only at levelized fuel prices higher than those observed in EIA data back to 1996 that an NGCC unit would become more expensive than a non-compliant coal unit. Even in this case, there would be net benefits associated with the standard from avoided health and environmental impacts. In response to commenter 9407, the EPA used the most recent estimates of cost of CCS based on vendor quotes for the CanSolv process, the process in use at Boundary Dam.  NETL (June and July 2015).
Reliance on EIA forecasts of no new coal plant construction is precarious
Commenter 9033 states reliance on EIA forecasts that no coal plants will be built is precarious and explains that EIA forecasts have consistently failed to see market fluctuations and interruptions and are revised annually and sometimes more frequently (e.g., points to EIA assumption of gas at $4.50 per mm Btu through the decade and prices have already risen in recent months to $5.50- 6.50 per mmBtu and sometimes higher).
Commenter 10555 states the cornerstone of this no cost, no benefit rule is an EPA belief that no one will build another coal plant. Notably, then, their entire rulemaking rationale arises from the EPA's belief that owners of newly built electric generating units will choose technologies that meet these standards even in the absence of this proposal due to existing economic conditions as normal business practice. This proposed standard is based on the degree of emission limitation achievable through natural gas combined cycle generation.  Commenter 10555 continues it is one thing to acknowledge that economic considerations will drive decisions on fuel source selection, but quite another to justify a complex, far-reaching regulatory scheme on those same economic considerations, which have proven to be uncertain. Commenter offers the example of the assumption that coal will not be economically competitive in the future appears speculative; especially considering the EPA basis that conclusion on unreliable assumptions relating to the future prices for natural gas. Commenter states that energy market projections are subject to much uncertainty. Many of the events that shape energy markets are random and cannot be anticipated. In addition, future developments in technologies, demographics, and resources cannot be foreseen with certainty.
The EPA disagrees with these comments.  As discussed in Chapter 4 of the RIA, the EPA evaluated a range of future scenarios based both EIA and EPA modeling projections.  The finding of no new non-compliant generating capacity in the period of analysis holds true over this range of future projections. In addition, the EPA presents analysis in Chapter 5 of the RIA that shows even under historically high natural gas prices, NGCC units would maintain a cost advantage over non-compliant coal units.
EPA did not use DOE-recommended cost data
Commenter 10036 states a review of the docketed material on interagency comments regarding the proposed rule shows that EPA did not use the cost data recommended by the Department of Energy (the organization that EPA cites as the best source of information on CCS technologies) and cites comments from Summary of Interagency Working Comments on Draft Language under EO12866 Interagency Review.  Commenter continues that those comments, including DOE's comments, clearly state that the single value cost estimates in then Table 4 (Table 6 in the rule as proposed) 91(79FR1476, January 8, 2014) (do not represent the cost of CCS technology. Commenter adds if one chose the midpoint of the ranges recommended by the reviewers, then the cost of electricity from CCS-equipped systems would increase by 15%. Commenter states further that such an increment should be placed on the values developed earlier in this comment package (i.e., 115% x $128/MWh, or $147/MWh), and that providing a margin of safety to allow the plant to meet regulatory requirements under a range of operating conditions would increase these costs further. Commenter 10036 continues, stating that providing a range of cost estimates, as EPA does for non-fossil fuel based technologies in Table 7 of the Preamble, is a reasonable approach to addressing cost uncertainty. 
 Cost estimates from the DOE NETL studies are presented as a range.  See, e.g. preamble Table 8.  Estimates for LCOE for nuclear are likewise presented as a range, consistent with advice from EIA staff, and with the approach taken by leading experts in the field, Lazard and Global CCS institute.  The EPA also noted at proposal that the DOE NETL costs reflected a range of -15% to +30% from the central point estimate.  79 FR at 1476; cost ranges are likewise presented in Table 7 of the proposed rule preamble.  Id. at 1477.   This comment, and its innuendo, are therefore incorrect and misplaced.
DOE cost uncertainty range
Commenter 10036 states providing a range of cost estimates, as EPA does for non-fossil fuel based technologies in Table 7 of the Preamble, is a reasonable approach to addressing cost uncertainty, and if EPA prefers to characterize this uncertainty for fossil-fueled generators with a "plus or minus" formula, then the Agency should state and discuss the range recommended by DOE, which represents DOE's present understanding of the current state of technology and energy markets (- 0% to +30%).
The EPA does present predicted costs as a range to represent DOE/NETL's recommendations regarding uncertainty in the capital costs of the projections. The range presented is -15% to +30%. See preamble section V.I.1. through 3.
Rule will keep older coal-fired units open and polluting
Commenter 8501 states that because electric utilities will not build any new coal-fired generating capacity under this rule, they are likely to maintain generating power in the existing older fleet of boilers that are less energy efficient and higher emitting than any new coal-fired generation would be, explaining that this scenario has played out before when earlier NSPS rules and New Source Review ("NSR") requirements were established. 
Commenter 10023 states that the proposed rule also will have the effect of encouraging owners and operators of existing coal-fired EGUs to continue to operate these units rather than retire them, out of concern that no new coal-fired units could be constructed for the foreseeable future if the proposed rule is adopted. Commenter adds that EPA claims that once it regulates CO2 emissions from new sources under section 111(b), it must regulate existing sources in those categories under section 111(d) and states that if correct, then EPA should have estimated the economic impacts of this proposed rule for existing sources.
Commenter 9735 states under the proposed rule, utility companies will not have the opportunity to build such highly efficient facilities because the cost and regulatory uncertainty of implementing these plants with CCS is too great. As a result, older, less efficient coal plants will be kept online longer and CO2 emissions from coal-fired power plants will actually increase over the lifetime of these plants.
Commenter 5731 states the consideration of remaining useful life is assigned to the states under CAA section 111(d)(1)(B). Kansas should be able to consider the age of each affected EGU within the state, the "sunk costs" for emissions controls already installed or planned for each EGU to meet other regulatory requirements, and the potentially stranded investments that would result from the permanent shutdown of an affected EGU.
Commenter 10086 states they believe this CCS mandate ultimately would perversely effect worldwide greenhouse gas emissions, leading to higher, not lower emissions, because of its chilling effect on bringing about true CCS demonstration and commercialization. 
The EPA's modeling, conducted using the Integrated Planning Model (IPM), as well as modeling conducted by the U.S. Energy Information Administration (EIA), showed that new generating capacity built through the period of analysis would be in compliance with the standard even in the absence of the regulation. As a result, we would not expect the proposed regulation to impact operating decisions.
This regulation impacts newly constructed EGUs, not existing generation sources. Accordingly, there are no impacts to existing sources as a result of this regulation. The EPA also notes that utilities and project developers have a range of new generation options to replace older, less efficient coal-fired power plants. These include natural gas combined cycle (NGCC) stationary combustion turbines and renewables such as wind and solar generation  -  or a new coal-fired plant with partial CCS meeting.
There is no credible economic evidence that the application of CCS in order to comply with the emission limits in this regulation would somehow deter future investment in CCS or deter technological innovation. On the contrary, the influence of regulatory actions that establish commercial markets for advanced technologies cannot be minimized. For example, the existence of national government regulation for SO2 emissions control stimulated innovation, as shown by the increase in FGD-related patent activity following initial SO2 regulatory requirements for EGU emissions. (See Technical Support Document/Memorandum "History of Flue Gas Desulfurization in the United States" (July 11, 2017) available in the rulemaking docket: EPA-HQ-OAR-2013-0495.
U.S. emissions comprise a small fraction of global CO2 emissions
Commenter 10091 states the relative impact that greenhouse gas emissions from the U.S. have on the future course of the earth's climate is rapidly diminishing. Instead the climate course into the future is being set by the world largest and developing nations, including China and soon India. Such a fact makes reducing greenhouse gas emissions from the United States an inconsequential (at least environmentally) effort. Globally, in 2011, humankind emitted 32,579 million metric tons of carbon dioxide (mmtCO2: according to the latest numbers form the U.S. Energy Information Administration, EIA) from the consumption of energy. Energy-related CO2 emissions from the U.S. in 2011 were 5,491 mmtCO2, or 16.9% of the global total. During the prior 10 years, global energy-related emissions of CO2 increased at an average rate of 786 mmtCO2/yr. This means that even a complete cessation of all energy-related CO2 emissions from the United States will be completely subsumed by global emissions growth in just 7 years' time. In fact, China alone, over the past 10 years, emitted on average 539 mmtCO2 of new emissions each year (over and above the total from the year before). This means that China's CO2 emissions growth would completely replace a complete shutdown of all U.S. emissions in just over 10 years. As this EPA Rule would have minimal impacts on U.S. carbon dioxide emissions (by the EPA's own reckoning), the time until any emission reductions achieved under this Rule would be completely overwhelmed by global emissions year-over-year growth is only a matter of days. Clearly there are no environmental impacts to be gained in such a situation.  
These comments are beyond the scope of this proceeding.  Section 111 (a) is a technology-based standard, and the new source standard adopted here faithfully implements its provisions.  Moreover, this standard applies to the largest domestic source of CO2 emissions, by a wide margin.  The EPA also made a rational choice not to control GHGs emitted in small amounts from new sources.  See preamble section III.G.  So the rule does reasonably discriminate between large and small volume GHG emissions.  Moreover, China has committed to reducing GHG emission by 2030, based in part on U.S. emission reduction actions (light and heavy duty vehicle standards), and proposals (under section 111 (b) and (d)).  China has also shown considerable interest in the CCS technology, visiting the Boundary Dam facility every few weeks, according to SaskPower executives.  See POWER magazine, Aug.1, 2015.
Agrees with EPA model showing new coal-fired plants not most economic choice
Commenter 9678 states agreement with EPA's modeling in support of this rule, which shows that new coal-fired plants do not appear to be the most economic choice through the analysis period for this rulemaking (79 Fed. Reg. at 1,475) Commenter also notes that the modeling documented in the RIA shows natural gas-fired EGUs being the economically-preferred alternative beyond the 2030 analysis period. 
Commenter 10242 quotes the proposed rule stating "It should be noted that under the EIA (Energy Information Administration) projections, existing coal-fired generation will remain an important part of the mix for power generation. Modeling from both the EIA and the EPA predict that coal-fired generation will remain the largest single source of electricity in the U.S. through 2040" Commenter remarks that, in reality, it is becoming increasingly more challenging to continue to utilize coal as a fuel because of the stringent regulations that are being imposed. The impact of multiple new regulations on utilities will have a direct impact on the cost of electricity for the average consumer. Power plants will have to strategize to accommodate for the costs associated with the addition of control equipment and fuel changes. This is evident in the number of coal-fired units that are being retired across the country.
Commenter 10869 states from 2008 to 2013, coal-fired power fell from about 48 percent of U.S. electricity generation to 39 percent. The shift has been driven primarily by the shale gas boom, which has dramatically lowered natural gas prices. Over the same time period, natural gas generation grew from 21 percent to over 27 percent of total electricity generation. EIA projects that very few new coal plants will be built through 2040 (EIA 2013). Market dynamics, including low natural gas prices and falling costs of renewable energy, are making existing coal-fired power plants increasingly uneconomic. A recent UCS report, Ripe for Retirement: The Case for Closing America's Costliest Coal Plants, 2013 update, analyzes the eroding economics of coal-fired power. We found that 59 GW of coal-fired power are more expensive to operate compared with existing NGCC plants once the costs of absent pollution control equipment is included in operating costs. Interestingly, about 13 GW of coal fired power plants are uneconomic even without installing new pollution controls; these are some of the oldest and most inefficient plants that have well outlasted their 30-year lifetimes. Commenter concludes that what this makes clear is that there is a significant opportunity ahead in making decisions about what energy resources will replace these retiring coal-fired power plants. Clean Air Act standards for new fossil-fired power plants can be a significant driver of those choices with regard to new builds.
The EPA thanks the commenters for these observations and notes that a number of different sources and scenarios support the overall conclusion that generation constructed in the period of analysis would meet the requirements of this regulation even in the absence of the regulation.
Cross-media impacts
Commenter 1902 states that EPA did not conduct proper peer review of the CCS technologies and the possible cross media impacts to water and soil under National Environmental Protection Act. Commenter continues that EPA did not meet its separate statutory obligations to conduct NEPA-like assessments to water use, impacts to endangered species, and possible contamination from CO2 or drilling wastes. This is both a violation of the Clean Air Act and as expressed under the Portland Cement decision.
First, EPA's actions under the Clean Air Act are not subject to NEPA review.  15 U.S.C. section 793 (c)(1).  Second, under section 111 (a), EPA must consider nonair quality health and environmental impacts of standards of performance as part of the process for determining if a system of performance is "best" and is "adequately demonstrated".  The EPA has done so here.  As explained in preamble section V.N., EPA has carefully considered potential for injected CO2 to contaminate underground sources of drinking water or be released to ambient air, and reasonably determined that the stringent standards for Class VI and Class II injection wells, complemented by the reporting and monitoring requirements in the subpart PP and RR rules assure against such releases.  EPA has also considered the issue of water use, as discussed in preamble section V.O.2.  No drilling wastes are associated with the standard, so the commenter's reference to such wastes is obscure.  Finally, EPA has considered whether the standards "may affect" listed species or designated critical habitat and reasonably determined that they do not.  See preamble section XIII.B.
Commenter 10048 states that it takes a significant amount of water to operate a generating facility, even without the addition of CCS. While the amount of water required by a facility varies by type, there is one commonality between all options -there is a significant increase in water demand required by CCS integration.
EPA acknowledges that capture operations at generating facilities can increase water consumption. But has reasonably evaluated the issue and found the water use to be manageable and decreasing in magnitude.  See preamble section V.O.2. .
Commenter 9426 notes that complications to pipeline permitting could result from issues related to waters of the U.S. and related regulations. Commenter 9195 stated that newly proposed changes to the Clean Water Act (CWA) could impact the viability of utilizing Nation Wide Permitting authorities-thus requiring thousands of CWA 402 and 404 related permits prior to construction of such a pipeline, and asked whether took these newly proposed changes into consideration in the rulemaking.
In 2015, the agency and the U.S. Army Corps of Engineers finalized a rule which more precisely defines "waters of the United States" under the CWA.  EPA does not agree that the changes would have a substantive effect on the ability of proposed CO2 pipeline proponents or other permit applicants to access Nationwide Permitting authorities under Section 402 and Section 404.
Commenter 9423 states the EPA's claimed health co-benefits of sulfur dioxide (SO2) and nitrogen oxides (NOx) reductions from the proposed rule are incorrect and invalid because the rule would actually result in an increase in NOx emissions. This increase in N0x emissions from CCS is also documented in the U.S. D0E National Energy Technology Laboratory (NETL) reports cited by EPA (Cost and Performance of PC and IGCC Plants for a Range of Carbon Dioxide Capture, May 27, 2011, D0E/NETL-2011/1498, Section 3.2.5). According to the NETL report, 50 percent CO2 capture on a supercritical pulverized coal (PC) unit would decrease the net plant efficiency from 39.3 percent to 32.9 percent, forcing the unit to operate at a higher firing rate to maintain the same net generation. The NETL report estimates this impact to the net plant efficiency would increase the N0X emissions from 0.608 lb/MWh to 0.646 lb/MWh. The EPA has not evaluated the environmental impact of the N0X emission increase that would result from the proposed rule.
Further, Commenter 9423 states the NETL report that the EPA cites indicates that even at the partial CO2 capture rates necessary to meet the proposed standard, the raw water consumption rate for a supercritical PC unit increases by 26 percent and for an IGCC unit, the raw water consumption rate would increase by at least 7 percent (Cost and Performance of PC and IGCC Plants for a Range of Carbon Dioxide Capture, May 27, 2011, D0E/NETL-2011-1498, pages 481-482). The EPA has not evaluated the impact of the additional water consumption that CCS requires.
The EPA's modeling, conducted using the Integrated Planning Model (IPM), as well as modeling conducted by the U.S. Energy Information Administration (EIA) showed that new generating capacity built through the period of analysis would be in compliance with the standard in the baseline scenario, and as a result, the requirements of the rule would not result in any behavior changes. For this reason, we do not project any benefits associated with the standards. (See RIA Chapter 4.) The EPA did conduct an analysis of the potential costs and benefits if an operator chose to build a coal-fired EGU compliant with the standard. (See RIA Chapter 5.) While the commenter is correct that there would be a small increase in NOx emissions, there would be a decrease in SO2 emissions. When all of the health benefits and disbenefits are totaled, the result is a positive health co-benefit. Additionally, there would be benefits associated with reductions in CO2. Because the illustrative unit is assumed to be compliant with all relevant standards in the baseline, there would be no costs associated with this increase.  See preamble section V.O.2 for the EPA's analysis of issues relating to water usage.
Commenter 10869 states research shows that today's electricity system cannot meet our needs in a future of growing demand for power, worsening strains on water resources, and an urgent need to mitigate climate change. Power plants require significant amounts of water for cooling purposes, putting a strain on local water resources which will be exacerbated in many parts of the country as our climate changes. But we can dramatically reduce these water and climate risks by choosing options such as renewable energy and energy efficiency. The power plant carbon standards, along with other standards and incentives, could also provide a path forward to get to a low-carbon, "water-smart" electricity future. However, an electricity mix that emphasizes carbon capture at coal-fired power plants could elevate water risks.
This comment is beyond the scope of the present rulemaking, although EPA has carefully considered the issue of water use in its assessment of what system of emission reduction is best.  See preamble section V.O.2.
Commenter 9195 states on March 6, 2014 colleagues from the Senate Environment and Public Works Committee inquired whether EPA had conducted any consultation with the Fish & Wildlife Service (FWS) regarding the Endangered Species Act (ESA) and whether a full analysis has taken place under the ESA.  Section 7 of the ESA requires the FWS consultation on any action that "may effect" a listed species or designated critical habitat. As the Senators pointed out, because the NSPS effectively removes coal as an option for electric power generation, the nation will need to rely on other energy resources, like nuclear, natural gas and renewables. This shift will certainly require additional habitat and the use of resources that have a history of harming endangered species. EPA testified that it had not consulted with the FWS in regard to the proposed rule for new power plants. Commenter asks: a. Why did EPA choose not to consult with the FWS in drafting this rule? And b. Has EPA consulted with the FWS in regard to the upcoming existing source rule? Why or why not?
As discussed in detail in preamble section XIII.B, EPA has considered whether the standards "may affect" listed species or designated critical habitat.  Very little, if any, new coal capacity is projected to be built, and this is projected for reasons unrelated to the standard of performance, see RIA chapter 4.  No commenter has indicated where such (hypothetical) capacity might be located, and for this reason the EPA is reasonably determining that the rule does not have potential for a specific impact on listed species in their habitats.  Nor does the final standard of performance make it impossible to build new coal capacity.  See generally preamble Section V.I.4.
Commenter 9776 states that of particular note is EPA's criticism of other federal agencies' proposed actions for the failure to address this same question. In point of fact, EPA criticized the Federal Energy Regulatory Commission's (FERC) Draft Environmental Impact Statement (DEIS) on a proposed natural gas liquefaction and pipeline project as recently as this March. 
EPA has in fact carefully considered issues of nonair quality health and environmental impacts, and potential impacts on endangered species in their habitats, as described in the previous responses in this unit.
Consider impacts of business relocation, expansion, retention
Commenter 3176 states EPA should consider the proposed standard's impact on industry and businesses as they are faced with the decision to locate, expand and/or remain in Alabama and the United States.  Commenter adds EPA should create policies and regulations that will facilitate competitively-priced electricity.

Commenters 9594 and 4814 state although the proposed NSPS is aimed at the coal-fired utility sector, these regulations will have a significant negative impact on U.S. manufacturing, including forging operations, in several ways: 1) the proposed rule will result in substantially higher energy prices and weaken the reliability of energy supplies. Forging is an energy-intensive process, and higher energy costs will impact U.S. forgers disproportionately; 2) higher energy costs will negatively impact the cost of the raw materials used in forging, such as steel and aluminum, which are also energy-intensive products.

Commenter 10032 states the Proposed Standard sets a dangerous precedent for other economic sectors since EPA has says it can regulate GHGs across the entire economy. Refining, manufacturing, food processing and all other segments of the economy will face increased fuel, electricity and other input costs.  Further, the Proposed Standard establishes many uncertainties and potential negative impacts for natural resource-based industries and most segments of the United States economy.  

Commenter 1695 states these will hinder Texas' ability to accommodate this future growth because of its requirement to install costly and commercially untested carbon capture and storage technology. As a result, there will be three major outcomes, a decrease in capital investment, less generation of jobs, and higher electricity rates. Commenter continues (1695) that for the past 8 - 10 years, Texas has created more jobs than all 49 other states combined and these GHG standards are not business friendly and will negatively impact capital investment in Texas, which will lead to less job creation.

Commenter 9602 disagrees with EPA's position in its Regulatory Impact Analysis (RIA) that this rule would not be "economically significant".  Commenter argues that this will be among the most economically significant rules EPA has ever proposed.  

Commenter 10870 states the Proposed Rule will not result in fuel diversity and divests states like North Dakota with the primary authority to determine what sources should be in a state's energy generation portfolio. By effectively banning new coal generation facilities, EPA is improperly becoming a regulator of energy - displacing a traditional and statutory role held by the states. In North Dakota, it is the Public Service Commission (PSC) that is vested with the authority to approve new coal fired EGUs.  Commenter continues that the proposed rule would effectively penalize energy producing and high growth States like North Dakota, where rapid economic development in the State has resulted in a growing demand for electricity.

Commenter 10396 states the proposed regulation will adversely impact Wyoming's economy as the leading coal supplier to the United States, adding that the regulation lacks sound reasoning, technological justification and will not provide regulatory certainty. Commenter 10396 continues that the proposed rule will cut jobs, increase power costs and stifle innovation. Commenter states in a resolution that its member and community will be negatively impacted by EPA's proposed greenhouse gas regulation. Commenter recommends that EPA either withdraw the proposed rule or set greenhouse gas emissions standards for new power plants to a level that is achievable using currently demonstrated and commercially available technology. Commenter 3107 states that low cost and dependable electricity is essential to economic growth, business success, and the livelihood of the citizens of Texas, among other benefits

Commenter 7433 states that this public utility commission has serious concerns about protecting Ohio consumers from high electric prices and from unexpected outages based on EPA's Proposed 111(b) Rule, and urges the Administrator to use its discretion to develop an emission limitation achievable through the application of the BSER. This approach should take into account the cost of achieving such reduction with the health, environmental, and energy market impacts of maintaining coal-fired EGUs. Commenter continues expressing concern that the proposed rule would effectively limit coal-fired or pet coke-fired generation from being constructed, even in instances where it may be necessary to increase reliability by hedging against market volatility.  Comment closes stating that the Administrator should use its discretion to conduct either a true cost-benefit analysis using non-pilot scale examples of CCS on coal-fired boilers or a system-wide cost-benefit analysis to determine at what level the coal-fired generation emissions limit should be set. In order to ensure that the analysis only incorporates applicable projects, the economic baseline of the analysis should not be calculated based upon generators that were shut down due to high costs.

Commenter 10238 states they generally support the regulation of carbon dioxide from new affected fossil fuel-fired electric generating units; however, USEPA's proposal appears to be very aggressive and will likely disproportionately affect co-op members throughout the United States during a time when the economy is still re-building.

Commenter 10662 states the expected surge in demand for natural gas due to regulatory policy, at the same time regulatory policy eliminates coal as an alternative to natural gas for new electric generating units, is bound to increase costs to electric consumers and raise the price of natural gas for residential, commercial and industrial consumers outside the electricity sector.

Commenter 8924 states existing and anticipated economic conditions should be seen as an opportunity by electricity generators to choose new generation technologies that would meet the proposed standard without additional controls, such as renewable energy sources like wind and solar. America has grown into a global clean energy leader, with the potential to go even further. Today there are 80,700 wind energy jobs and 142,698 solar energy jobs across the nation. Construction of turbines, solar panels, and associated parts also has the potential to enliven the manufacturing industry in numerous states. This new income for rural communities means more resources for fire and police departments, schools, infrastructure, and other public services. Rather than build new coal plants that require carbon capture technology, many states will have more reason to invest more heavily in renewable as a tool for economic development. Commenter concludes that rural communities and small towns can benefit greatly from standards that incentivize renewable, homegrown energy. This, combined with the harmful consequences these communities face as a result of continued use of coal-fired generation, illustrate the importance of setting meaningful standards. 

Comment 9196 states it is likely that petroleum coke production will be used in facilities overseas, resulting in even greater carbon emissions due to its transport and less efficient end-users. So, in cases like Las Brisas project in Texas, the rule is likely to increase what the Agency now calls carbon emissions. Further, the commenter contends that by not holding the line on the price of electricity, the rule creates an incentive for energy-intensive manufacturing industries to seek locations overseas.  Commenter continues, stating numerous studies find that regulatory burdens of this sort imposed on energy prices and energy supply cause plant closures and maximize the potential that manufacturing jobs will move overseas.

Commenter 9594 states that they oppose the proposed rule and that EPA should perform a thorough analysis of costs and benefits, accounting for the cascading effects costly energy regulations will have on businesses, markets, employment and households.

Commenter 7977 states EPA's economic analysis does not demonstrate how the proposed rule will alter future U.S. GDP, employment, and productivity. Kentucky has the most electricity-intensive economy in the U.S. since Kentucky industries use more kWh of electricity per GDP and are more sensitive to potential changes in electricity generation costs than any other state. The loss of domestic manufacturing jobs will result from this proposed rule.

Commenter 3107 states they and the community they serve, will be negatively impacted by EPA's proposed greenhouse gas regulation. They recommend that EPA either withdraw the proposed rule or set greenhouse gas emissions standards for new power plants to a level that is achievable using currently demonstrated and commercially available technology.

Commenter 10046 states effects of NSPS proposals on the economic health and viability of the industry have traditionally been the key focus of EPA assessments under EPA's historical approach to NSPS. EPA has carefully assessed whether the costs are within the range that could be absorbed while not unduly depressing economic viability, including whether or not they could in fact be passed on: Pressure Sensitive Tape and Label Surface Coating Industry; Kraft Pulp Mills; Basic Oxygen Process Furnaces; Beverage Can Surface Coating Industry; Synthetic Organic Chemical Manufacturing Industry; Coal Preparation Plants. Commenter 10046 continues when EPA has concluded that the industry, or a segment thereof, would not be capable of absorbing or passing on the costs, it has found them to be unreasonable: Nonmetallic Mineral Processing Plants; Petroleum Dry Cleaners; Onshore Natural Gas Processing. Subcategory 10555-5839 states the IPM model making the required economic forecast that natural gas-fired EGUs will be the facilities of choice until at least 2020 is insufficiently robust to capture EIA's expectation of price increases starting just 10 years from now.
The EPA did consider the costs and benefits and other impacts of the proposed rule, as required by Section 317 of the Clean Air Act, as well as Executive Orders 12866 and 13563. This analysis is presented in the Regulatory Impact Analysis for the regulation. The EPA's modeling, conducted using the Integrated Planning Model (IPM), as well as modeling conducted by the U.S. Energy Information Administration (EIA) showed that new generating capacity built through the period of analysis would be in compliance with the standard even in the baseline scenario and, as a result, the rule would not lead to changes in behavior. This finding held true even under a number of alternative scenarios. As a result, the EPA projected there would be negligible costs, benefits, energy impacts (including changes to electricity prices), employment impacts, or economic impacts associated with the rule in the period of analysis. (See Chapter 4 of the RIA.) Based on these conclusions, we would not expect business relocation, impacts to manufacturing, or the transfer of industrial activity to other countries. In response to the comment of the State of Wyoming, the EPA would also not expect the new source standard to impact use of coal mined in the state for the same reason: even assuming historically high natural gas prices, there is no evidence that new coal capacity would be cost-competitive with NGCC.

Because this rule is not estimated to have costs or benefits greater than $100 million, it is appropriately classified as not economically significant. This rule impacts newly constructed electric generating units. Comments regarding regulation of other sectors are outside the scope of this action.
Jobs impacts
Commenter 8966 calls for a cumulative analysis of the effects that the enactment of the rule will have, showing that significant hardships will be placed on the coal industry, local communities in coal-producing regions, and the national economy, explaining that the proposed standard will undoubtedly prevent the construction of new coal-fired EGUs. Commenter adds that in response to the dramatically reduced demands for coal in energy generation, tens of thousands of coal miners and supporting employees would be laid off, and communities built around the coal industry would be harmed. States dependent on coal mining would see a huge outflux of former coal employees.
Commenter 8966 states that it is projected that nearly 600,000 jobs may be lost over ten years due to power plant and coal mine closures and the proposed rule, and while the proposed rule confirms that there will be significant coal-related job losses, it will also indirectly damage the hundreds of communities that rely upon the coal industry.
Commenter 8966 states that in Greene County, PA, three of the top four major employers are mining companies and the average annual salary for a Greene County miner totals $88,633.43, and by contrast, the average county wage for all occupations is $42,880, or less than half of what a Greene County miner on average annually earns. In Harlan County, KY, nearly 50% of mining jobs have been eliminated in the past year from closure of over 20 coal mines due to waning demand for coal, contributing to a 16.3% unemployment rate. Similarly, in Union Township, PA, the closure of the Mitchell Power Station is expected to reduce property tax funding by over $600,000, leading to significant reduction in funding for the local school district. The same plight has occurred in Louisa, KY and Moundsville, WV.
Commenters 8966 and 10028 state that a cumulative consideration of the regulatory impact on employment, communities, and the regional or national economy is required by statute and executive order, explaining that in determining whether a particular technology constitutes a BSER under CAA Section 111, EPA is required to weigh the costs and energy or 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." "[T]he functional equivalent of a NEPA impact statement" is required, including an analysis of social and economic impacts to local communities, encompassing "impacts that are due to past, present, and reasonably foreseeable actions. 
Commenter 8966 states other provisions of the CAA demonstrate the importance of cumulative consideration of employment and the economic effects, citing, for instance, CAA Section 125's requirement for coal-fired plants to only use regionally available coal in cases of "significant local or regional economic disruption or unemployment"; Section 321 which requires EPA to conduct "evaluations of potential loss" of employment which may result from administration or enforcement of the provision in this chapter"; and Executive Order 12866 which requires all agencies to "tailor" regulations to impose the least burden on society, including individuals, businesses of differing sizes, and [small communities]" taking into account "the costs of cumulative regulations." 
Commenter 8966 states that cumulative consideration reveals that the proposed rule severely diminishes employment opportunities, community welfare, consumer access to reliable and competitively priced electricity, and state and national economic vitality.
Commenter 7977 states that Section 321 of the CAA requires that the Agency account for the employment effects which may result from administration of the CAA. The cost-benefit analysis relies upon conclusions which do not account for unemployment impacts of the proposed rule. Commenter continues, stating that EPA's economic analysis does not demonstrate how the proposed rule will alter future U.S. GDP, employment, and productivity. Commenter notes that Kentucky has the most electricity-intensive economy in the U.S. since Kentucky industries use more kWh of electricity per GDP and are more sensitive to potential changes in electricity generation costs than any other state. 
Commenter 9505 states that the proposal does not indicate whether the Administrator complied with section 321 of the CAA, which requires her to conduct continuing evaluations of potential loss or shifts of employment that may result from the administration or enforcement of the Act. The record does not show that EPA has complied with section 321 with respect to the current proposal.
Commenter 3176 states that the EPA must consider that such rules will result in the loss of high-paying jobs in the coal industry. Today, there are many hard-working families who depend on the coal industry to make an honest living and who will not be able to maintain that standard of living if the proposed GHG standards are promulgated by the EPA.
Commenter 9594 states that EPA's proposed rule on GHG emissions will substantially increase the cost of energy in the U.S., thereby decreasing the competitiveness of U.S. industries. As a result, investments and emissions will flow to countries with higher CO2 emissions intensities and U.S. policies will produce economic losses in the U.S. but will not achieve its stated objective. It is important that any additional regulation of greenhouse gas be cost effective, attainable and protect American jobs and the economy. EPA should perform a thorough analysis of costs and benefits, accounting for the cascading effects costly energy regulations will have on businesses, markets, employment and households.
Commenter 8501 states that the impacts of this rule on Indiana, particularly the Indiana coal industry, are significant, explaining that the Indiana coal industry directly employs 6,210 workers and provides another 28,680 jobs in businesses that support and supply the coal producers. Mining contributes $3.2 billion to Indiana's Gross Domestic Product. Coal mines in Indiana contribute more than $10 million per year to predominantly rural communities through property tax revenues, and if the investments in our industry decline, these rural communities will suffer greatly. Commenter is concerned that the proposed rule will close the door to future investment in the industry which may lead to a decline in the infrastructure that supports the industry and the local community.
Commenter 9197 states that the retirement of these facilities-when combined with the effective ban on construction of new coal facilities that this Proposed Rule would impose-will lead to devastating, permanent losses of hundreds of thousands of jobs in the boiler and pollution control fabrication, mining, construction, and rail transportation industries. Although commenter recognizes that some of these plant retirements may be driven in part by the low price of natural gas, commenter urges EPA to avoid exacerbating the severe headwinds that are already facing the coal industry by imposing an unachievable standard for new coal-fired power plants.
Commenter 3179 offers a local government resolution stressing that industries provide many local jobs and a considerable amount of income, and also generate federal, state and local revenues to help pay for schools, emergency services, and infrastructure improvements; and that the coal produced in our region is naturally low in sulfur, mercury, and ash, while simultaneously high in energy value, and resolving that the governing body opposes restrictive and punitive federal carbon regulations on existing power plants, in favor of a flexible, state-based, free market approach that will attain the air quality goals  more efficiently and completely than federal regulations;  that  States should include a high degree of flexibility, and take into account the geographic and economic realities at the state level; and that the individual states should be allowed the freedom to adopt their own policies on a timeline that works for them, and that minimizes any economic disruption.
Commenter 8966 states that cumulative consideration reveals that the proposed rule severely diminishes employment opportunities, community welfare, consumer access to reliable and competitively priced electricity, and state and national economic vitality. Over 350 coal-fired power plants, accounting for nearly 60 GW of power are ripe for retirement. As new coal-fired power plants will be unable to be built if the proposed rule is enacted, Pennsylvania and similar states with a disproportionately older fleet of coal-fired power plants and/or a significant coal mining industry will be hit hardest. Commenter notes that in its proposed rule of nearly 100 pages, EPA devotes two lines on the employment impacts of the rule, simply stating that it believes this rule will not have any impacts on employment or labor markets. However, layoffs and coal power plant closures have already begun, particularly in anticipation of the EPA's enactment of the proposed rule. In Pennsylvania, one of the largest producers of both coal and energy derived from coal, 11 coal-fired power plants totaling 5,160 MW have either been shut down or scheduled for retirement in the past two years. None of these plants would be able to be replaced by new units if the proposed rule passes, as the cost of compliance would be astronomical. In light of these power plant closures, demand for coal is declining. This translates to job losses for coal miners and other related employees. It is estimated that the number of coal mine employees dropped by ten percent between 2012 and 2013, with nearly a 20% decrease in the Central Appalachian region. This trend will only be magnified upon enactment of the rule.
Commenter 8957 states that the impacts of this rule on all entities, great and small, will be severe and adverse, citing the recent lawsuit brought against the EPA by Murray Energy Corporation on March 25, 2014. In their issuance of Murray Energy Corporation's intent to sue the U.S. EPA, they state: "Murray Energy is the largest producer of underground coal in the United States and employs over 7,100 people in towns and cities across the country. Commenter believes that in establishing this rule, the EPA is going to adversely affect many other industries including steel mills, cement kilns, lime kilns, petroleum refineries and other major producers of CO2 emissions.
Commenter 6871 states that forcing the nation to abandon its most abundant and economic energy resource is not good energy or environmental policy, and will harm workers and consumers through reduced jobs and higher energy costs.
Commenters 9320 and 9661 state EPA has not fulfilled its duty under the CAA to consider job losses. The proposal's Regulatory Impact Analysis includes no analysis of the potential macroeconomic or jobs impacts of the proposed rule because EPA projects that its proposal will not alter what is currently projected for new-unit construction and therefore will have no "notable macroeconomic or employment impacts." This conclusion is indefensible, especially because EPA's proposal effectively bans new coal-fired generation at the same moment as other EPA regulations are causing significant retirements among existing units.
Commenter 9735 states that North Dakota is one of the top ten states for percentage of our electricity generated from coal, with coal-fired power providing almost 80 percent of the state's electricity needs. At the same time, our state maintains some of the lowest rates per kilowatt-hour in the nation. North Dakota is also one of the top ten coal producing states in the nation. It is estimated that over 4,000 North Dakotans were directly employed as a result of lignite related coal activities in 2012, and as many as 13,000 other jobs in the state were supported indirectly by the lignite coal industry. The coal industry is an economic engine for several counties in west-central North Dakota, providing average wages in many of those counties in excess of $75,000 per year in 2012, exceeding both state and national averages.
Commenter 10607 states that Section 321(a) of the CAA requires EPA to "conduct continuing evaluations of potential loss or shifts of employment which may result from the administration or enforcement of the provision of this chapter and applicable implementation plans, including where appropriate, investigating threatened plant closures or reductions in employment allegedly resulting from such administration or enforcement." EPA did not consider other effects, including a reduction in the number of coal-fired power plants, particularly in the primary generating markets of the Central and Northern Appalachian coal industry. This will, in turn, dramatically reduce the level of coal mining employment, which provides some of the highest paying jobs in the region, particularly for those without a college education. This will affect not only the incomes of those directly employed, but also the tax base in the states and municipalities where they live, leading to increased poverty. Increased poverty will adversely affect health outcomes over large areas of low income populations (children living in low income families or neighborhoods have poorer health outcomes; low income, not race or lifestyle, is greatest threat to health). EPA did not account for the disparate health effects that the rule will have on the coalfield communities that rely on coal mining for direct employment and for taxes that support local schools and public facilities-all in violation of its obligations to consider environmental justice in its federal actions. 
Commenter 9505 states that the proposal does not indicate whether the Administrator complied with section 321 of the CAA, which requires her to conduct continuing evaluations of potential loss or shifts of employment that may result from the administration or enforcement of the Act. The record does not show that EPA has complied with section 321 with respect to the current proposal.
Commenter 9320 states that EPA has not fulfilled its duty under the CAA to consider job losses, explaining that although EPA projects that its proposal will not alter what is currently projected for new-unit construction and therefore will have no "notable macroeconomic or employment impacts," this conclusion is indefensible, especially because EPA's proposal effectively bans new coal-fired generation at the same moment as other EPA regulations are causing significant retirements among existing units.
The EPA disagrees with these comments. Section 321(a) authorizes the EPA to conduct "continuing evaluations of potential loss or shifts of employment which may result from the administration or enforcement of the [CAA]." Section 321(a) does not prescribe the scope, timing, or frequency of these evaluations and does not require the EPA to conduct any specific type of analysis, such as the cumulative analyses described by some of the commenters. Section 321(a) also does not require the EPA to conduct employment evaluations as part of the rulemaking process or as a precondition to the issuance of a final rule. On the contrary, Section 321(d) clearly states that Section 321 does not authorize or require the EPA "to modify or withdraw any requirement imposed or proposed to be imposed under [the CAA.]" Nevertheless, in the exercise of its discretion, the EPA did evaluate the potential employment impacts of both the proposed and final rules in the RIAs accompanying those rules. Thus, the commenters are incorrect that the EPA failed to consider potential employment impacts.

The EPA also disagrees with the commenters' factual assertions. While some commenters predict future job losses, they did not provide any evidence to support their assertions. Indeed, these comments are largely conclusory and speculative. Other commenters point to past job losses in the coal industry and other sectors. As these commenters acknowledge, however, past job losses were caused by other factors, such as low natural gas prices, not the final rule. Still other commenters rely on mistaken statements to support their claims, such as the assertion that the final standards will effectively ban future coal plants. On the contrary, the EPA's modeling, conducted using the Integrated Planning Model (IPM), and modeling conducted by the U.S. Energy Information Administration (EIA), both show that new generating capacity built through the period of analysis would be in compliance with the EPA's final standards even in the absence of those standards. As a result, the final rule will not lead to changes in behavior or job losses. The EPA even found this to be true under a number of alternative scenarios, including where natural gas prices rise to historically high levels. For more details, see Chapter 4 of the RIA. Furthermore, EPA disagrees with the comment regarding EIA analysis.  EPA's consideration of EIA's independent analysis is reasonable.
Social cost analysis
Commenter 7977 states EPA's social cost analysis in the RIA is incomplete and is deficient in addressing the secondary price effects corresponding to the increased opportunity costs of goods produced in manufacturing intensive states, like Kentucky, explaining commenter's modeling suggests that a 10 percent increase in the real price of electricity would, on average, be associated with a 1.1 percent reduction in state GDP. This would result in a loss of almost $2 billion dollars to the state of Kentucky. Commenter adds EPA's analysis should reflect what portion of GDP loss is due to the proposed rule's effect on market conditions. Commenter adds that EPA has already recognized this deficiency by requesting comment on the role of economy-wide modeling in U.S. EPA analysis of air regulations. 

Commenter continues 7977, stating that EPA's analysis should reflect the likely consequence of manufacturing states having increased electricity costs resulting in less heavy industry and manufacturing in the regional economy and in the United States than currently exist. Commenter adds that companies' migration to countries with less stringent environmental regulations diminishes the regulatory benefit, threatens U.S. GDP, and compromises national security by lessening U.S. independence within the manufacturing sector.  Commenter 7977-4688 states EPA's statement that that economy-wide modeling results are not available, results are not thorough, and the unknown effects are potentially significant on gross domestic product (GDP) and increased unemployment in predominantly manufacturing states.
The EPA disagrees with the commenters' statements that there will be impacts to electricity prices as a result of this regulation. EPA's modeling, conducted using the Integrated Planning Model (IPM), as well as modeling conducted by the U.S. Energy Information Administration (EIA), showed that new generating capacity built through the period of analysis would be in compliance with the standard even in the baseline scenario and, as a result, the rule would not lead to changes in behavior. This finding held true even under a number of alternative scenarios, including historically high natural gas prices. As a result, the EPA projected there would be negligible costs, benefits, energy impacts (including changes to electricity prices), employment impacts, or economic impacts associated with the rule in the period of analysis.
Human health impacts
Commenter10091 states the EPA's RIA is mistaken in asserting that "this rule would result in net benefits from avoided negative health effects." In fact, the overall state of human health is improving as evidenced from a doubling of the average American's life span since 1900. Commenter provides a figure from the Centers for Disease Control (CDC), showing several measures of mortality across the U.S. Even though the raw number of people dying each year is on the increase, this increase is a result of an increasing and aging population. Correct for these attributes (dark blue line) and you see that a large and on-going decline. Commenter states if you want to go looking for an anthropogenic climate change signal, you need to go looking in this overall trend in declining death rates. Commenter further states you surely won't find that anthropogenic climate change slowed this decline. You might find that climate change hastened to it. 

Commenter 10091 continues regarding health impacts of extreme weather events, overall mortality from extreme weather events (hurricanes, floods, lightening, tornados) shows a long-term decline in the United States when properly adjusted for population changes. This leaves little room to implicate anthropogenic climate change as producing a negative health benefit from altering the character or occurrence of such events in the United States - an alteration which the best science does not provide reliable guidance as to its direction, much less the magnitude. 

Commenter 10091 also notes regarding heat-related mortality what is not included in the above figure is mortality from extreme heat events which are often billed as the leading cause of weather-related mortality in the U.S. This situation is readily rectified by a new study examining trends in heat-related mortality across the U.S. using data from 1987 through 2005 conclude: this study provides strong evidence that acute (e.g., same-day) heat-related mortality risk has declined over time in the US, even in more recent years. This evidence complements findings from US studies using earlier data from the 1960s through mid-1990s on community-specific mortality rates, as well as European studies that found temporal declines in heat-related mortality risk, and supports the hypothesis that the population is continually adapting to heat. These conclusions confirm the long-standing finding of earlier work that the U.S. population's sensitivity to extreme heat is declining - despite a rise in temperature leading to an increased magnitude and frequency of heat events. The cause of this declining sensitivity in the face of rising heat is likely found in a collection of adaptations including increased access to air-conditioning, better medical care, community response programs, heat watch/warning systems, and biophysical changes. There is no reason to think that such response measures won't continue to exist and be improved upon into the future. A study summarizing the recent findings on declining heat-related mortality trends in both the U.S and Europe made this observation: Some portion of this response [the declining sensitivity to excessive heat events] probably reflects the temporal increase in the frequency of extreme-heat events, an increase that elevates public consciousness and spurs adaptive response. In this manner, climate change itself leads to adaptation. The bottom line implies that through the collective adaptive response, climate change not only does not result in negative human health outcomes, but may, in fact, spur positive ones. These findings render the EPA's contention to the contrary to be shallow and misleading and unfit to justify this regulation.

Commenter 10091 adds that this point is further emphasized by a direct calculation of the global temperature savings achieved through this regulation assuming the best-case scenario in which all existing coal-fired power plants are replaced by power plants which meet the emissions caps proposed in this regulation. This would result, according to the EPA, in an approximately 40% reduction in carbon dioxide emissions over existing emission levels from coal-fired power plants. According to the EIA, in 2011, the consumption of coal in the U.S. released 1,874 mmtCO2. A reduction of 40% would be equivalent to 750 mmtCO2 savings per year which would reduce total U.S. CO2 emissions by about 15%. Using EPA's Model for the Assessment of Greenhouse-gas Induced Climate Change (MAGICC) model run under the SRES A1B scenario and assuming the default climate sensitivity of 3.0d.C, this results in a net global temperature savings (a reduction of the total MAGICC-projected global temperature rise) of 0.01 degrees C by 2050 and 0.014 degrees C by 2100. Applying a equilibrium climate sensitivity of 2.0 degrees C (which is in better accordance with the recent scientific literature, as described in Section II.C above), the best-case global temperature savings drops to 0.0075d.C and 0.01d.C by 2050 and 2100 respectively. And these numbers are too high because they assume that the 750 mmtCO2/yr emissions saving begins immediately. In reality if it is ever achieved through this ruling, it will take place only after all existing coal-fired plants have been replaced, which will take decades, and push the temperature savings reported above further into the future. In all cases, the temperature savings from this EPA Rule are so small as to completely undetectable and inconsequential to all local, regional, and global environmental systems. As such, commenter concludes, the rule serves no environmental purpose, now or in the future, and should be withdrawn.

Commenter 10091 states further, the bulk of the scientific research on the topic of trends in heat-related mortality indicates that in the face of a warming climate, the rate of heat-related mortality is declining - a result of a collection of adaptive measures, some likely spurred by the warming itself. As heat-related mortality marks one of the primary perceived public health threats from anthropogenic climate change in the U.S., the fact that the scientific literature contradicts the EPA's assertions on this topic requires a reexamination of this justification for the proposed Rule. And finally, the EPA admits that this Rule will have little if any impacts on U.S. carbon dioxide emissions, writing: [T]he EPA anticipates that the proposed EGU New Source GHG Standards will result in negligible CO2 emission changes, energy impacts, quantified benefits, costs, and economic impacts by 2022. Commenter states they show, that even assuming best case emission reductions occurring beyond 2022, that the climate impacts of this proposed Rule will be scientifically undetectable and environmentally inconsequential. In light of these critical issues, we recommend that the EPA's proposed Standards of Performance for Greenhouse Gas Emissions from New Stationary Sources: Electric Utility Generating Units be withdrawn.
First, section 111 (a) and (b) require the EPA to adopt technology-based standards, not standards predicated on a particular environmental outcome.  Second, the implicit argument in many of these comments that unless an individual regulatory action eliminates or substantially reduces the adverse effects of climate change, it has no benefit and is arbitrary, was  rejected by the D.C. Circuit. Coalition for Responsible Regulation v. EPA, 684 F. 3d at 128-29.  As in that case, there can be meaningful emission reductions here.  See preamble section V.K. quantifying the delta over time between a single power plant emitting at levels achievable by a highly efficient SCPC and emitting at the level of the final standard of performance reflecting partial CCS.

Costs
Pollution control technology cost is a normal and proper expense of doing business
Commenter 9514 remarks the legislative history states that the costs of applying pollution control should be "considered by the owner of a large new source of pollution as a normal and proper expense of doing business." H.R. Rep. No. 95-294 at 184. The comment adds that, among other things, the 1977 amendments were "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." Id. at 186.
The commenter correctly recites this legislative history.
Section 111 authorizes national and regional cost analysis
Commenter 9514 states EPA's cost analysis satisfies the statutory standards for a reasonable methodology based on the record. See, e.g., Sierra Club, 657 F.2d at 330 ("The language of section 111 . . . gives EPA authority when determining [BSER] 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.").
See preamble Sections V.H and I.
Deregulated states
Commenter 9777 states the direct impacts of increasing electricity costs nationwide vary to some degree. In states with regulated utilities some or all of the cost of new generation will be passed directly to the consumer. In deregulated states, it will not make economic sense to build cost prohibitive EGUs because the costs will never be recovered unless energy prices rise significantly. The lack of fuel flexibility caused by EPA's proposed rule will ultimately result in rising natural gas prices that will also impact the consumer. Commenter states that low income families will be the most negatively impacted by rising energy costs, having to spend a higher percentage of income on electricity or reduce their electricity use which can have negative effects on the health of those families in times of excessive hot or cold weather. Commenter continues that EPA misunderstands how cost of controls is addressed within a deregulated market. In a deregulated market, however, the generator bears the costs of emission controls, so the decision to build or not build is based on the market price of power. The consequence may be both an increase in costs to the electricity consumer and adverse effects on reliable power. In the 2011 report Cost and Performance Baseline for Fossil Energy Plants Vol. 3b30, DOE/NETL establish cost and performance baselines for various "low rank coal plants" configurations. Modeling included a supercritical pulverized coal plant similar to existing Texas lignite plants. The model projected "required cost of electricity" (COE) with and without CO2 capture to be $62.20/MWh and $116.40/MWh respectively. 
Commenter 10046 states EPA's cost analysis is contrary to statutory requirements and its established pattern and practice in evaluating cost reasonableness. EPA also represents an arbitrary and incomplete assessment of the economic effects of CSS on the power sector. Indeed, EPA altogether neglected to demonstrate the economic reasonableness of partial CCS in states with deregulated power markets. Commenter continues that EPA did not consider whether partial CCS costs could be accommodated in deregulated energy markets. A number of states have adopted a deregulated market structure for the provision of power, and this market structure dictates a very different resource planning and selection process than those evaluated by EPA. EPA never analyzes whether or how above-market CCS coal units could be accommodated in deregulated markets. It is an important part of the problem which EPA is obligated, but did not, to consider. EPA's analysis does not consider the cost differentials and distinctions between regulated and deregulated energy markets. EPA relies on non-price factors to conclude that the costs of coal with partial CCS can be accommodated by the industry. EPA then concludes that these non-price factors are germane to all energy market generation decision-making because EPA does not consider any other industry segments. Nowhere in the proposed rule does EPA explain how the non-price factors are relevant considerations in determining whether or not the added costs of CCS can be tolerated under deregulated market conditions. 
Further, Commenter 10046 remarks that in deregulated jurisdictions, by contrast, utility procurement activities are typically limited to competitively procuring relatively short-term (1-3 year) contracts that also offer a hedge against volatile spot market prices.  Also, commenter states that in deregulated jurisdictions, utilities do not typically make long-term generation investments that enter the utility's rate base. Generating resources are financed and developed by competitive, profit-maximizing generation suppliers in response to market signals. Thus, most deregulated utilities do not engage in formal Resource Planning processes. Instead, they develop processes that aim to minimize the costs of short-term, market-based procurement. 
Commenter 10046 states when new capacity is needed in deregulated markets such as PJM and NYISO, private companies assess whether they can obtain adequate revenues to cover the generation investment. These revenues come from three main sources: (1) a capacity payment; (2) various ancillary services; and (3) to the extent the new unit is dispatched, energy payments. Each of these revenue streams is priced through competitive market-based structures.  Hence, by definition, coal with partial CCS cannot be accommodated by project developers in deregulated states. Commenter remarks that the market is specifically designed not to accommodate non-price considerations such as fuel diversity preferences, but rather allows entry only for competitively-priced power. Since a new coal plant with partial CCS would begin losing money from its first day of operation, and that would continue indefinitely through the 2020s according to EPA's robust RIA, it could neither be built nor financed. Commenter notes that EPA asserts that its Section 111 standard would remain valid even if higher costs of CCS in some geographic locations would tilt the economic against new coal-fired construction.  Nevertheless, commenter states, to the extent EPA is asserting that a Section 111 standard does not need to be economically reasonable for every potential new source everywhere that is simply incorrect. First, whatever may be the case if there are isolated geographical pockets that present unusual cost issues, it cannot be supposed that if partial CCS is facially economically unreasonable in deregulated states, as we have shown, then EPA may ignore those states and declare partial CCS economically reasonable anyway. Nothing in Section 111 empowers EPA to mandate a performance standard that is economically unreasonable in entire states, and in a number of states at that. Commenter 10046 states that this is implicit in the analysis of BSER from the Sierra Club case on which EPA so heavily relies. There, as EPA observes in the preamble, the court directed EPA to balance economic, environmental, and energy considerations to determine what the best standard is with reference to the whole country, such that a water-dependent technology might be appropriate in the East, but inappropriate in the West due to water scarcity issues. (Id) The court did not authorize EPA to ignore important factors present in different parts of the country, but instead directed EPA to assess those impacts and make adjustments to its BSER determinations to reflect those differences. Hence, EPA is obligated to address the different impacts deregulated power markets present on the industry's economical ability to accommodate BSER costs. Commenter adds that past agency practice also directs EPA to ensure that economic costs are reasonable in all cases. Thus, in the NSPS for Asphalt Processing, EPA provided an exemption from an enclosure requirement to a segment of the industry because EPA did not have enough information to be certain the costs would be reasonable in all cases. Similarly, EPA's discussion of the Primary Copper, Zinc and Lead Smelter NSPS in the instant proposal's preamble is instructive. There, the costs of BSER were reasonable for two types of smelting processes but not for a third. EPA concluded: 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. Consequently, commenter concludes, EPA must determine if EPA's BSER determination is economically unreasonable for new coal plants locating in deregulated states, and if so as it obviously would be EPA is obligated to establish a standard that is economically reasonable in those states.
Commenter 10046 states EPA also wholly failed to consider whether partial CCS costs could be accommodated in deregulated energy markets. EPA's analysis fails in every meaningful way to consider the cost differentials and distinctions between regulated and deregulated energy markets.  Commenter continues it makes this point to contend that its standard would still satisfy the economic reasonableness requirement for new sources locating in areas where EOR, and EOR revenue, is not practicably available. EPA bases this conclusion on bits and pieces of legislative history that, to the extent they are even relevant, seem more focused on technological feasibility issues and not economic reasonableness, and on case law concerning another section of the CAA that specifically addresses technological feasibility. And EPA's specific point is illusive because it specifically decided to base its BSER analysis on the assumption that EOR is not available.  Commenter adds it cannot be supposed that if partial CCS is facially economically unreasonable in deregulated states, as we have shown, then EPA may ignore those states and declare partial CCS economically reasonable anyway. Nothing in Section 111 empowers EPA to mandate a performance standard that is economically unreasonable in entire states, and in a number of states at that.
First, the commenter assumes that new coal capacity without CCS would be price competitive in competitive wholesale markets, but that new coal meeting the standard of performance reflecting performance of partial CCS would not be price competitive.  There is no basis for that assumption.  As shown in RIA 4, new coal capacity will not be cost-competitive with NGCC for the foreseeable future, and this projection holds true even under sensitivity cases where natural gas prices are assumed to rise to historic levels.  See Sierra Club, 657 F. 2d at 337-38 (upholding cost analyses under section 111 reflecting analysis of primary estimates and sensitivity cases).  See RIA at 4.5.4  p. 33 ("even the most favorable combination of regional variability in capital costs and delivered fuel prices represented by EIA are insufficient to support new, unplanned, conventional coal-fired capacity in the analysis period"); id. at p. 29 ("As an illustration, one potential price path that would achieve a $10/MMBtu on a 20-year levelized basis in 2020 is a natural gas price path 30 percent higher than EIA's low resource scenario in all years (see Figure 4-5).  This illustrative price path to achieve a $10/MMBtu levelized price would result in an $11.02/MMBtu annual real price in 2030 and a $13.81/MMBtu real price in 2040. Even on this significantly higher price path, a representative NGCC unit would have a lower LCOE than a non-compliant coal unit. What this information indicates is that natural gas price forecasts need to be notably higher than the highest forecast in the AEO 2014 scenarios before we would expect that general market dynamics would favor new non-compliant coal generation over new compliant natural gas generation as the fossil-fuel technology of choice to satisfy demand") (emphasis added).   Similarly, even in its sensitivity analysis that assumes higher natural gas prices and electricity demand, EIA does not project any additional coal-fired power plants beyond its reference case until 2023, in a case where power companies assume no GHGs emission limitations, and until 2024 in a case where power companies do assume GHG emission limitations.

Second, the EPA disagrees that the difference between the final standard of performance and SCPC alone creates the price difference that would make new coal non-price competitive.  See preamble section V.I.4.  The commenter's statement that from its first day, a plant with partial CCS would be losing money applies equally to SCPC without partial CCS.

Third, the commenter does not address that many competitive wholesale markets include states that have already adopted laws which significantly restrict any new coal capacity, rendering the issue moot in such states.  See RIA section 2.8 (restrictions in entire Northeast and Oregon, all of which are deregulated).

We note that even in deregulated states participating in competitive wholesale electricity markets, states can take actions to incentivize the building of generation for policy reasons not determined by price-competitiveness. For example, Massachusetts, a deregulated state participating in ISO New England, passed legislation requiring all distribution companies in the Massachusetts January 2, 2013 and December 31, 2016 to "twice in that time period to jointly solicit additional proposals from renewable energy developers and, provided reasonable proposals have been received, enter into additional cost-effective long-term contracts to facilitate the financing of renewable energy generation, apportioned among the distribution companies under this section." A deregulated state participating in a competitive wholesale market could take a similar action to incentivize the construction of coal with CCS. Further, we note that a deregulated state participating in a competitive wholesale electricity market could take actions to incentivize the building of generation for fuel diversity purposes without running afoul of FERC's exclusive jurisdiction over wholesale electricity rates under the Federal Power Act.
Stranded costs
Commenter 1681 states coal plant owners are expected to invest over $30 billion in the near- term to further reduce emissions of conventional air pollutants. The EPA must ensure that carbon regulations do not cause additional premature closures of coal units and, therefore, strand investments in emission controls.
New source standards, by definition, do not involve stranded assets. 
Municipal utilities compliance costs
Commenter 10392 states that while it is impossible to estimate possible compliance costs for impacted municipal utilities in advance of EPA issuing proposed standards for existing units (under Sec. 111(d)), decisions made by EPA and by the states will ultimately impact compliance costs and the overall cost-effectiveness of any standards for existing units. Commenter shares AMP's/OMEA's concerns that EPA's assumption that there are no costs to its new unit NSPS proposal could be carried forward into the agency's upcoming existing source rule.
Commenter 9497 states what has been demonstrated by recent efforts to develop CCS for power plants at scale is that CCS is difficult and more costly than initially anticipated. Recognizing these risks, the MPSC imposed performance standards and expectations on Kemper that shift risk to the utility. This sort of accountability, which MPSC would expect to be imposed by almost any state commission charged with ratepayer protection, is unlikely to be attractive to utilities contemplating the implementation of partial CCS technology in its current state.
See preamble Section V.I.4. 
Cost achievability does not capture all expenses; National level cost analysis inappropriate
Commenter 0588 questions whether an emissions standard based on partial CCS would survive a reasonable achievability analysis, adding that the administrator did not account for the representativeness of the cost data on which she relied. Commenter adds the EPA "vitiates" the "purpose of a rulemaking proceeding" when the agency reasons "on the basis of inadequate data." Commenter contends that by ignoring the representativeness of the data on which it relied, the administrator's NSPS risks imposing impermissible regional discrimination.
 
Commenter 9780 states EPA's interpretation of "cost" to allow it to consider costs on a national basis - irrespective of exorbitant unit-specific costs - is not reasonable nor supported by case law. [EPA asserts that case law on section 111 provides that "to be adequately demonstrated," the system must be "reasonably reliable, reasonably efficient, and reasonably expected to serve the interests of pollution control without being exorbitantly costly in an economic or environmental way." Cost is also a consideration in the "achievable" prong of the section 111(a) test. 
 
Commenter 9780 states that the Costle decision only provides that EPA's cost analysis authority is not limited to a plant-level analysis, adding that is not the same as saying that EPA may disregard a plant-level analysis altogether. The commenter continues that if the costs of implementing a technology are so extreme as to preclude the use of a system of emission reduction at regulated sources, then the system is not "adequately demonstrated" and the standard is not "achievable" and, therefore, national or regional level impacts of imposing the standard are immaterial to the analysis.
 
Commenter 9780 states the facts in Costle are the inverse of this scenario. In Costle, EPA initially proposed a standard of performance corresponding to an 85 percent removal of SO2 emissions, and presumably found the costs of such a standard to be reasonable. However, EPA ultimately finalized the less stringent variable percentage reduction standard. One of EPA's rationales for finalizing a more lenient standard was that the original, more stringent standard would have imposed unreasonably high costs on a regional and national basis. See 657 F.2d at 336-338 (describing EPA's econometric analysis and findings). The Costle court held that it was permissible for EPA to consider these broader cost impacts in settling on a more lenient variable percentage standard, even after initially finding that the 85 percent standard was adequately demonstrated and achievable at individual plants.
 
Commenter 9780 continues whether at the initial "adequately demonstrated" stage or in determining what system is "best", EPA cannot use national-level cost analysis to issue a standard that ultimately is not adequately demonstrated or achievable at the plant level, or as a way to overcome the fact that plant-specific costs are exorbitant and unreasonable. Rather, as in Costle, EPA may use such a "grand scale" analysis to shift to a less stringent standard if the Agency finds that the standard would achieve comparable environmental benefits at lower overall cost.
 
Commenter 9396 states EPA is inappropriately expanding the basis for evaluating the cost for complying with emissions standards, from the source level to a much wider basis, e.g. to industry-wide, regional and national levels Commenter adds that EPA states that CCS qualifies as BSER because it will not have adverse impacts on the power sector, national electric prices or the energy sector. EPA's assertion that it is not limited to assessing costs at an individual source, but rather can assess costs on a region-wide or nationwide basis opens the door for a host of unnecessarily high cost upgrades to the electric sector and other regulated businesses.  Adopting EPA's new stance would have a very significant impact on all NSPS pollution standard development for utilities and other industries by largely divorcing costs to directly impacted facilities resulting from required actions.
 
Commenter 9194 states EPA must show that BSER is "adequately demonstrated" and "achievable" at the source level at reasonable cost. EPA's assertion that it is not limited to assessing costs at an individual source, but rather can assess costs on a region-wide or nationwide basis opens the door for a host of unnecessarily high cost upgrades to the electric system Commenter states that larger considerations are in addition to the requirements of the statute to examine BSER at the plant level, not in place of it.
 
Commenter 10023 states that EPA improperly focuses on the costs and effects of its CCS mandate on a nationwide, long-term scale at the expense of considering its effect on individual new sources. Commenter explains that the CAA only permits EPA to consider long-term effects in addition to source-level impacts.
 
Commenter 9407 states EPA's conclusion that coal cannot complete with natural gas for new electric generation is based on an arbitrary set of presumptions, explaining that EPA used the LCOE metric in its cost comparisons and thus, for example, regional differences resulting in lower costs in some geographic areas are not reflected in LCOE calculations.
 
Commenter 8966 states many operators of CCS systems will also be required to transport captured supercritical carbon to a storage site. Depending on the proximity of the plant to a suitable geologic formation, transport costs may range from $2.50 to $5/ton CO2 per 100 km, depending on the pipeline's mass flow rate and surrounding terrain. While these costs may be marginal for operators in close proximity to a suitable site, they can quickly balloon for plants situated in an area several hundred miles from such a formation, amounting to tens of millions of dollars annually. Thus, enactment of the rule would inevitably impose exorbitant costs on plant operators and the coal industry, contrary to law.
 
Commenter 9780 states EPA relies on data (in its RIA analysis Table 5.5) that show partial CCS increases costs for a supercritical pulverized coal (SCPC) unit by 34.6 percent for capital, 28.5 percent for fixed operations and maintenance (O&M), and 36.4 percent for variable O&M. By the Portland Cement standard, these cost increases are not reasonable.
See preamble Section V.H where the EPA shows that the standard of performance is reasonable, considering costs, on both a per-plant and national basis.
Sector-wide versus individual plant basis for cost impacts
Commenter 9513 states although the use of CCS technology will incur some additional cost at the individual unit, given the projected number of new coal plants that would be built, with or without promulgation of the regulation, the CCS requirement will not have a significant impact on electricity rates, either regionally or nationally. EPA is correct in its determination that, under the CAA, the assessment of cost impacts is to be made on a sector-wide basis, rather than on an individual plant basis.
See previous response.
Broader geographic scale costing yields more lenient standards
Commenter 9780 states the court in Costle specifically rejected arguments by environmental group petitioners that EPA must base section 111 standards on an assumption that all plants would use the system of emissions reduction corresponding to the "maximum technologically feasible level of control." 657 F.2d at 329 Instead, the court upheld EPA's issuance of a variable percentage reduction standard based on EPA's determination that a less stringent, variable standard "would achieve virtually the same emission reductions at a national level as a uniform approach but at substantially lower costs." In other words, the Costle decision only affirmed EPA's consideration of total reductions and cost as a rationale for selecting a more lenient emissions standard than the one preferred by environmental group petitioners. 
Commenter 9780 states the Agency implies that a standard based on partial CCS is required "regardless of feasibility and cost" because it will result in substantially greater reductions than would result if new fossil fuel-based power plants did not use CCS. Yet, the Agency also insists that the additional costs from the proposed standards "will, on a nationwide basis, be small because no more than a few new coal-based projects are expected." 79 Fed. Reg. at 1480. Assuming EPA is correct that costs will be low because only a few new coal-based plants would be built anyway, then EPA has no basis for also arguing that a meaningful additional amount of total emissions reductions would result from requiring partial CCS instead of basing the section 111 GHG standards on highly-efficient coal-based generation technology.
The final standard of performance is justified based on an assessment of costs on an individual plant basis, as well as sector  - wide.  The implication commenter 9780 sees is not correct.  It is not EPA's position that reduced emissions can, a priori, eliminate consideration of cost in determining whether a system of emission reduction is "adequately demonstrated" for purposes of section 111 (a).
Use current costs
Commenter 10870 states the cost of the Proposed Rule will have harmful impacts upon North Dakota and the regional and national economies, and commenter adds that EPA is interpreting the CAA in such a way that justifies the current high costs of installing CCS systems on new coal units, for example the position that EPA is not restricted to assessing costs on a source-by-source basis, but may consider costs at the industry or national level-where the cost barriers to CCS are less apparent, and that costs of a particular control technology can be considered over an extended period of time into the future, rather than at the time of the rulemaking alone. Commenter believes the cost of CCS will not come down in the future because of a lack of demand for the technology, and that current costs should be used to assess the economic viability of CCS.
The EPA is assessing costs on both a per-plant and sector-side national basis and founds those costs to be reasonable, whether either of these metrics is considered alone, or together.
Fuel price volatility
Commenter 2470 states history has demonstrated that fuel costs can be volatile and the most cost-effective generating option can change over time. Further, commenter 8501 states the cost and system reliability implications of the proposed rule are understated and do not adequately take into consideration the swings in natural gas prices, the tendency for natural gas shortages, and the significant capital investments that must occur to deliver natural gas to new gas-fired power plants. There will be significant economic cost with the rule as a result of transition to greater reliance on natural gas as the fuel of choice for electricity generation.
Commenter 1419 states that they find industry economic arguments false. Industry argues against standards and limits citing costs for compliance.
The Regulatory Impact Analysis for the rule includes several illustrative analyses, including examining the costs of the rule under a range of natural gas prices. (See Chapter 5 of the RIA.) It is only when levelized natural gas prices increase significantly, to levels above those seen in EIA data going back to 1996 that there would be costs associated with the rule. Even in those cases, the health and climate benefits associated outweigh the costs except when examining unprecedented natural gas prices.  See also RIA chapter 4.5.4 indicating that new non-compliant coal capacity would not be price competitive with natural gas, even assuming natural gas price increases to historic highs. In all of the scenarios examined from AEO 2014, an NGCC unit remains more economical than a non-compliant coal unit, even in the scenarios that are most favorable to the construction of new coal (i.e., higher than projected natural gas prices and lower than projected coal prices.)
Allow supercritical boilers without CCS
Commenter 10870 states it appears the impetus for establishing the New Source Performance Standard (NSPS) under Section 111(b) of the CAA is for EPA to establish a legal pretext for EPA to seek to regulate existing EGUs under CAA Section 111(d), and if EPA's objective is to achieve Section 111(d) regulatory authority over existing EGUs, this can be accomplished without requiring CCS for new facilities, explaining that EPA could set a CO2 standard based on the most efficient super critical boilers without CCS. Commenter adds under CAA Section 111(b)(l)(B), EPA would have the opportunity to review in eight years whether it is necessary to revise the CO2 standard that is based on the most efficient super critical boilers. Commenter 10095 states a 2013 EPRI study compared the results of 12 scenarios that incorporated EPA's proposed standards to a baseline that allowed new coal-fired plants to be constructed without CCS, and EPRI's scenarios evaluated various natural gas price paths, the availability of new nuclear and new inter-regional transmission, and the lifetime of the existing coal fleet. Commenter continues that additional costs are incurred by the electricity sector in all scenarios due to the proposed standards. EPRI found the costs range from $15 billion to $293 billion through 2050 (net present value in 2010), and as required by Executive Order 12866 (1993), EPA must assess these costs and determine that the benefits of the proposal, if any, justify the costs.
Commenter 10618 states there is also an unfair bias against new supercritical coal within the LCOE calculations based on the assumed operation and maintenance costs. The values used by EPA from NETL for FOM and VOM of $70.6/kW-yr and $7.70/MWh (2011$) respectively are significantly higher than the $31.18/kW-yr and $4.47/MWh (2012$) being used by EIA. This further skews the comparison of natural gas versus conventional coal. 
Commenter 9194 states EPA has heavily tipped the scales to "environmental impact" and claims that a need to assure "meaningful reductions" in emissions is what prevents EPA from determining that super-critical pulverized coal (SCPC) and Integrated Gasification Combined Cycle (IGCC) coal plants without CCS are BSER. Section 111 of the CAA does not address achievement of ambient air standards and is not a section of the CAA assigned specific emissions reduction goals. EPA's over-weighting of emissions reductions is absolutely critical to its designation of coal with CCS as BSER. Further, EPA provides no analysis of the non-air quality environmental impact of the proposed rule on non-EOR sequestration, and no analysis of the energy penalties that occur with CCS. 
Commenter 9194 continues EPA should have compared the SCPC emissions to the typical CO2 emissions rate of existing coal-fired generating units. The CO2 emission rates of a new SCPC unit are significantly lower than the typical existing coal-fired EGU and would meet EPA's desire for significant CO2 emission reductions as shown by the table below. 
Commenter 9775 states that the Bonanza solid-fuel waste fired project proposed in Uintah County, Utah is designed and permitted to utilize lower grade by-product of coal washing facilities and would be a relatively small circulating fluidized bed (CFB) unit. The proposed unit is permitted to a very low emission standard for NOx, SO2, and particulate matter, in many respects comparable to a gas fired unit, but the capital cost structure of such a CFB u n it is lower than a large, supercritical pulverized coal unit. The more economical cost of such a "niche project" compares competitively to gas fired alternatives, especially with added environmental and community benefits of disposing landfilled coal fines. The proposed standard, if it is applicable to all future units, effectively eliminates the ability to realize co-benefits of these diversified project opportunities. Low, stable energy prices and reliable power are key drivers for Utah's economy, and coal provides a significant amount of Utah's base load electricity. 
In response to commenter 9775, the Deseret source is not a new source under the final standard of performance.  In response to comments urging selection of SCPC as BSER, see preamble Sections V.P.1 and V.K. (documenting the delta in CO2 emissions between an SCPC plant and a plant emitting at the level of the standard of performance). Further, as noted in other comment responses, the final standard of performance considers all the decision factors of section 111 (a), and does not assume a priori that emission reductions obviate consideration of other statutory factors.
New coal-fired power plants using higher efficiency technologies are competitive with natural gas combined cycle power 
Commenter 9201 states that new coal-fired power plants using higher efficiency technologies are competitive with natural gas combined cycle power. They state that modest adjustments to EPA's input assumptions in the Reference Case conditions show conditions under which SCPC and NGCC are equivalent in terms of LCOE, and these modest changes erode the cost advantage of NGCC over SCPC found in EPA's assessment. Commenter challenges EPA's assumptions are unfounded and incorrect, and point to a lack of a robust and economically sound assessment of the ability of varying generation sources to compete. 
Commenter 7976 states the lower combined cycle heat rates also mean that the combined cycle plants are much more competitive on the California power grids than for peakers. This results in the dispatch of combined cycle plants at a much high capacity factor than for peakers. Table A-3 (below) confirms that reasoning. California's modern combined cycle fleet generated 10 to 20 times as much energy as California's peaker fleet with only a 50% advantage in heat rate. Commenter adds that this data strongly implies the economic superiority of combined cycle because the much higher energy sales associated with higher capacity factors can support higher capital costs per installed KW. Combined cycle plants sometimes require a capital investment per installed KW that may exceed peaker plant investment by as much as a third, depending upon the project specific technologies and variations in regulation, land costs, labor costs, etc. Commenter offers the example of a project's capital cost alternatives, an excerpt from the Alternatives Analysis prepared by Brazos Electric Cooperative Inc. (Texas) in 2007, with the consulting assistance of Black & Veatch.
Commenter 7976 continues that Table 1 in California Energy Commission's Wholesale Cost of Electricity, 2009 Report projects that the energy cost rate of electricity from a combined cycle plant (in California) is a fraction of the cost from simple cycle plants. That's because the higher capital cost rate of combined cycle plants is amortized over a much higher level of energy production than simple cycle, which makes the $/MWh cost rate much lower for combined cycle. Commenter states that a reasonable conclusion is that the energy produced by combined cycle generation is generally much more economical (in terms of $/MWh of energy generated) than simple cycle peaker generation, even though the capital cost rate of combined cycle plants may be higher than the capital cost rate of simple cycle peaking plants.
Further, Commenter 10928 remarks that by effectively banning new higher efficiency coal power plants, EPA denies the nation the opportunity to maintain a diverse electric generation supply to fleet future load growth and replace the aging base load power fleet.
Commenter 10870 states the Proposed Rule will not result in fuel diversity and divests states like North Dakota with the primary authority to determine what sources should be in a state's energy generation portfolio. Commenter continues it is within the State of North Dakota's discretion to determine how best North Dakota's significant electricity demand can be met. North Dakota has an abundant supply of lignite coal that can be used to meet the future projected electricity demands. New efficient lignite-fueled baseload electric generation facilities should not be prohibited by the Proposed Rule for being an option available for meeting this substantial projected demand.
Commenter 10667 states Texas is the 5th largest coal-producing state in the U.S. Texas has about 23 billion tons of lignite deposits, with about 10 billion tons economically recoverable in today's market. There is enough economically recoverable lignite remaining to sustain Texas' current consumption for the next 100 years (these reserves far surpass oil and natural gas together in terms of in-state Btu equivalent energy reserves). This rate of consumption is significantly at risk, particularly if EPA finalizes a rule requiring the installation of CCS technology. 
Commenter 11134 requests EPA reconsider regulations on new coal plants. The proposed rule will have an ultimate "trickle down" effect on many other parts of the industry. For example, commenter is a coal terminal located south of New Orleans, their terminal would certain feel the effects if domestic production fell, as well as their contractors and vendors that depend on us for jobs. Before making any drastic decisions, please think about the consequences on competition (price of energy), economy, and unemployment.  Commenter requests thinking about improving rather than removing coal from the energy mix and look at new an affordable technologies to keep our environment clean.
EPA is not precluding the construction of new coal-fired generation, and the rule includes the flexibility to promote construction of new coal capacity with technology to meet the requirements.  For example, there are multiple compliance pathways to meet the final standard of performance, including compliance options that are not dependent upon use of CCS. In addition, EPA's modeling, conducted using the Integrated Planning Model (IPM), as well as modeling conducted by the U.S. Energy Information Administration (EIA) showed that new generating capacity built through the period of analysis would be in compliance with the standard even in the baseline scenario and, as a result, the rule would not lead to changes in behavior. This finding held true even under a number of alternative scenarios. As a result, the EPA projected there would be negligible costs, benefits, energy impacts (including changes to electricity prices), employment impacts, or economic impacts associated with the rule in the period of analysis. (See Chapter 4 of the RIA.)

Regarding the comments by Commenters 10870 and 10667 that express concern about fuel diversity in North Dakota and Texas respectively, as producers of lignite. There is nothing in the final standards that precludes the use of lignite or prevents construction of new lignite-fired EGUs in those states. In fact the EPA specifically examines the achievability of the finals standards of performance over a range of operating conditions including startups, shutdowns, malfunctions, and the use of a variety of fuels, including the low rank subbituminous coal and lignite. See section V.J in the preamble and the in a Technical Support Document (TSD)  -  "Achievability of the Standard for Newly Constructed Steam Generating EGUs" available in the rulemaking docket.
Call for Flexibility and cost minimization analysis of standard
Commenter 10034 states that EPA should commit to working with EGU operators to gauge whether its standard does in fact provide operational flexibility and minimize costs.
Commenter 9772 recommends that EPA study the potential impact to our country's future energy security that would result from reducing the diversity of available future power sources. Commenter also recommends EPA move away from its regulatory approach to eliminate coal from America's energy portfolio and instead look for ways to incentivize transitional improvements such as construction of more efficient power plants and cost-effective carbon capture and sequestration technologies.
The final standard of performance for fossil-fuel fired EGUs can be achieved in a number of ways, and is not constrained geographically.  
Need cumulative costs impact of regulated sources
Commenter 3176 states they are not aware of any meaningful analysis undertaken by the EPA as to the cumulative cost impacts resulting from implementation of, and compliance with, the suite of pending and issued rules affecting electric utility generating units. Considering the proposed carbon restrictions will address new and existing units, the need for a cumulative analysis is particularly justified. Commenter adds that it is important for the consuming public to be advised of the potential rate impacts associated with implementing the full suite of the EPA's recently proposed and newly issued regulations.
 
Commenter 9396 states that not examining the cumulative impact of its regulations means neither the price nor supply impacts of its rules have been adequate evaluated and the correct types of analyses needed to understand the impact on adequate supplies have not been conducted.  These estimated supply, price and reliability impacts from previous rulemakings do not include layering additional uncertainty and risk onto the electricity generation from EPAs proposed NSPS for CO2 which will have the practical effect of eliminating the development of new coal based generation. At a time when utilities need to plan and execute hundreds of millions of dollars of investments in existing units to comply with the CSAPR and MATS rules, EPA's decision to issue this proposed rule only adds greater uncertainty to the investment decision making process.
 
Commenter 10618 states  EPA's economic modeling used in this rulemaking has not appropriately assessed the impacts of the final MATS rule and other pending regulations, which will lead to the retirement of many coal-fired generating units, further increasing the demand and hence the price for natural gas. The associated reduction in coal use will also influence coal pricing (and reduce coal prices), making new coal fired generation more viable economically. Notably, when spreads between gas and coal prices reach approximately $4 per MMBtu, coal plants become economic to build relative to combined cycle gas plants.
 
Commenter 10082 states EPA should develop the rule for the electric power sector taking into account the cumulative impact of those rules on the various generation options.
EPA's modeling, conducted using the Integrated Planning Model (IPM), as well as modeling conducted by the U.S. Energy Information Administration (EIA) showed that new generating capacity built through the period of analysis would be in compliance with the standard even in the baseline scenario and, as a result, the rule would not lead to changes in behavior. This finding held true even under a number of alternative scenarios. As a result, the EPA projected there would be negligible costs, benefits, energy impacts (including changes to electricity prices), employment impacts, or economic impacts associated with the rule in the period of analysis. (See Chapter 4 of the RIA.) The baseline for this analysis included existing regulations, so this conclusion takes into account impacts of those actions.
Fuel diversity includes coal
Commenter 9034 states if coal were eliminated as a fuel source, then the grid will no longer have a reliable and affordable fuel source to fall back on when there are localized shortages of natural gas. Commenter adds the United States must have an "all of the above" energy policy.
Commenter 3093 strongly supports a portfolio strategy for domestic energy development. We believe a broad energy portfolio allows for the kind of economic growth and innovation that is key to sustainable prosperity for the entire country. 
Commenter 9596 states EPA should regulate CO2 emissions in a manner that does not foreclose future fuel-use options, explaining that it would be unwise for the federal government to develop environmental regulations that pick winners and losers in energy markets. Rather, the best long-term strategy for ensuring stability in U.S. energy markets is to allow all sources of energy to compete on a level playing field. For these reasons, commenter believes EPA should adopt an NSPS that keeps coal as a fuel option if it makes good economic and business sense to build new highly efficient, well-controlled, coal-fueled generation in the future.
See preamble Section V.I.4.
Call for parametric sensitivity analysis
Commenter 9666 states the RIA did not conduct a parametric sensitivity [analysis] as presented in this paper but rather, addressed individual (and not cumulative) changes in capital cost and fuel price that moved in the same direction. In summary, the inputs assumed for Figure 5 represent one set of realistic conditions under which NGCC and SCPC are equivalent in terms of levelized cost of electricity.  The commenter provided discussion of EPA's sensitivity analysis.
The commenter is correct that EPA did not conduct a parametric sensitivity analysis as part of this rule. The RIA for the proposed and final rules relied upon sector-wide analysis conducted using the Integrated Planning Model (IPM), as well as modeling conducted by the U.S. Energy Information Administration (EIA). Both of these analyses showed that new generating capacity built through the period of analysis would be in compliance with the standard in the baseline scenario, and as a result, there would be no change in behavior as a result of the standard. In addition, the analysis considered a number of alternative scenarios developed by EIA. This finding held true even under the alternative scenarios that would be most likely to result in new coal-fired capacity. As a result, the EPA projected there would be negligible costs, benefits, or energy impacts (including changes to natural gas prices) associated with the rule in the period of analysis. See RIA Chapter 4. 

Comment 3.3-16a: Commenter 9666 includes as attachment A to its comments, a study of its consultant, Mr. Cihanowicz.  That study maintains that new SCPC without CCS could be cost-competitive with new NGCC, the inference then being drawn by commenter 9666 being that a standard of performance based on some amount of CCS would render coal capacity non-cost competitive.  The commenter maintains that the key variables underlying the projections in the proposed RIA and EIA analyses are susceptible to interpretation, and by making realistic but different assumptions, new SCPC is cost-competitive.  Specifically,
   * CUA.  The commenter acknowledges that "the cost impact of the present permitting environment is real but should be handled as a separate accounting charge" (p. 5);
   * Variability in Capital Cost.  The commenter notes the variability across the various NETL studies and the -15%/+30% range for estimates (through 2013 studies);
   * Fixed and Variable Operating Costs.  The commenter again notes the ranges in the NETL studies
   * Cost of Coal and Natural Gas  The commenter does not challenge EIA predictions for natural gas cost (through 2040), calling it "the best estimate available" (p. 11), but does maintain that coal prices are variable.
   * Looking to these variables, the commenter performs a sensitivity type of analysis as follows:
   * Using capital recovery values of 12.4% and 11.6% for , respectively, SCPC and NGCC;
   * Given capital cost uncertainties, the commenter argues for a decrease in SCPC (based on "near collapse for SCPC" predicted, p. 13) and an increase for NGCC;
   * "eliminating financial bias" and assuming both SCPC and NGCC are low risk, for purposes of financing (pp. 13-14);
   * Adjusting operating and maintenance cost by 5-7% fixed and 15-27% variable for both SCPC and NGCC;
   * Raise estimated price of natural gas by $1/MBtu
   * Decrease coal prices by approximately $.50/MBtu.
The commenter maintains that under these assumptions, SCPC would be cost competitive with NGCC but for the CUA, with which it disagrees.

Response 3.3-16a: The EPA relies on the reasonableness of its estimates of cost, and its projection of no new non-compliant coal capacity being built in the review period.  The EPA's modeling, conducted using the Integrated Planning Model (IPM), and corroborated the U.S. Energy Information Administration (EIA), showed that new generating capacity built through the period of analysis would be in compliance with the standard in the baseline scenario. This finding held true even under a number of alternative scenarios.  In particular, sensitivity cases that EIA conducted in the AEO 2014, as well as the AEO 2013, separately examine higher economic growth, lower coal prices, no risk premium for greenhouse gas emissions liability from conventional coal, and lower oil and natural gas resources. None of these sensitivity cases forecast unplanned additions of coal-fired capacity without CCS in the analysis period.  See RIA at pp. 4-9 and Table 4-3.  Of the 31 scenarios contained in the AEO 2014, none project new coal-fired capacity in the analysis period used by the EPA for this RIA, "including the four scenarios that may be considered most favorable to the development of coal-fired capacity".  See RIA at 4-13.  Note that these assumptions include several of those in the commenter's sensitivity analysis: no carbon uncertainty adder and decreased coal prices.  See generally Sierra Club v. EPA, 657 F. 3d at 337-38 (accepting EPA cost estimates for section 111 standard as reasonable based on primary and sensitivity analyses conducted by EPA).  

Many of the commenter's suggested sensitivities reflect changes from estimates used in the NETL studies, based on (rather highly selective) choices from among the ranges presented in those estimates.  EPA believes the primary estimates in NETL (2015) to be reliable.  An indicia of this is that the NETL estimates for a highly efficient SCPC.  The final BSER is a highly efficient supercritical PC unit implementing partial CCS to meet a standard of 1,400 lb CO2/MWh-g. The AEP John W. Turk facility is an example of a highly efficient supercritical PC. In comments of AEP (p. 76), AEP represented the cost of the Turk facility as $2,885/kW. The DOE/NETL estimates for such a facility is $2,842/kW (NETL, 2015  -  for a plant using bituminous coal). This close agreement is another validation of the NETL cost methodology.  

The commenter's selected sensitivities, therefore, do not appear to be especially reliable or plausible to the EPA.  We believe the RIA analysis showing no new non-compliant coal generating capacity during the review period, even under assumptions most favorable to development of that capacity, to be reasonable and reliable.
Fuel cost
Commenter 9666 discussed the uncertainties in fuel price projections and offered alternate fuel price inputs that the commenter states are equally viable. The commenter presented the results of a sensitivity study, comparing the levelized cost of electricity from both SCPC and NGCC for the Reference Case, addressing alternate values of capital cost, finance charges, fixed and variable operating cost, and fuel price. The commenter provided in their Figure 5 results for both SCPC and NGCC generating equipment. Their results had fuel prices between natural gas and western coal as equal. Commenter states in summary, Figure 5 shows successive changes to four key cost inputs - capital, financing, operating and maintenance, and fuel price - remove any premium in the levelized cost of electricity for coal-fired SCPC versus NGCC. Each generates power for about $69-70/MWh.
The EPA's modeling, conducted using the Integrated Planning Model (IPM), as well as modeling conducted by the U.S. Energy Information Administration (EIA) showed that new generating capacity built through the period of analysis would be in compliance with the standard in the baseline scenario, and as a result, there would be no change in behavior as a result of the standard. As a result, the EPA projected there would be negligible costs, benefits, or energy impacts (including changes to natural gas prices) associated with the rule in the period of analysis. In addition, the Regulatory Impact Analysis for the rule includes several illustrative analyses, examining the costs of the rule under a range of natural gas prices. This finding held true even under higher than anticipated natural gas prices. See RIA Chapter 4 and 5. See also response 3.3-16a immediately above, responding to Cichanowocz study. 
Commenter 9666 states Table 1 (provided by commenter and entitled "Comparison of Fixed Operating Costs ($/kW-yr) and Variable Operating... ") shows a factor of 2-3 variance in estimates for both fixed and variable O&M between five DOE-sponsored studies of SCPC and IGCC.  For NETL reports, the scope of activities addressed in the fixed and variable O&M costs are similar. Table 1 demonstrates that estimates of fixed and variable operating cost - similar to capital cost as depicted in Figure 2 - depend on the source document. The 2013 RIA used values from the fifth report (DOE/NETL-2007/1397) which predicts the highest fixed O&M for both SCPC ($70.6/kW-y) and NGCC ($26.7/kWyr). The variable (non-fuel) O&M costs selected for the 2013 RIA were the highest for supercritical coal ($7.74/MWh) but near the lowest for natural gas/combined cycle ($1.76/MWh).
See response 3.3-16a above, showing, among other things, that the NETL primary estimate for SCPC matches very closely AEP's estimate for its Turk plant.  The commenter therefore lacks a basis for picking values from the range of previous NETL studies. 
Variability in capital cost 
Commenter 9666 states capital cost studies sponsored by the DOE - all conducted by reputable contractors - could vary by such a magnitude in only a few years' time, implying significant uncertainty in the estimating methodology. Commenter explains the Department of Energy (DOE) has issued six studies since 2007 estimating the capital cost of generating equipment, almost invariably including SCPC and NGCC. These studies typically address SCPC both with and without carbon capture and sequestration (CCS) equipment, along with integrated gasification/combined cycle, also with and without CCS. The commenter provided brief descriptions of the studies and notes the capital costs of SCPC and NGCC projected by these six studies vary significantly. All costs are escalated to a 2011-year dollar basis. The earliest work - published in 2007 and based on market forces for generating equipment in the 2003 to 2006 timeframe - projects the least capital cost for both SCPC and NGCC. These estimates reflect market forces preceding the cost pressures that were incurred in the middle part of this century's first decade due to strong global demand for process equipment. Subsequent studies issued from 2010 through 2012 reflect the strong global demand for process equipment. For example, the RW Beck study for the EIA - issued in November of 2010 - reported the highest capital cost for both SCPC and NGCC equipment. But a DOE/NETL report published less than 2 years later (DOE/NETL 341/082312) - released August of 2012 - projects lower SCPC costs by $1,000/kW. The estimate for NGCC equipment over this same time period differs by $200/kW.  Commenter continues (9666-894) none of the six studies was conducted to support the design, contracting, or construction of an actual plant, and thus, these estimates are classified as "budgetary." A significant degree of uncertainty - typically reported as +30% and -15% - characterize budgetary estimates. EPA selected the fifth NETL study (DOE/NETL-2007/1397, Revision 2a in September 2013) to support the RIA. Of interest is a sixth study (also released September 2013) that shows capital costs continue to relax, with a SCPC capital requirement of $2,283/kW - approaching pre-2007 levels. In summary, Figure 2 demonstrates the volatility of capital cost estimates for SCPC and NGCC. Two NETL reports were released in September 2013 - both available from which to base an analysis, and EPA used the study with higher SCPC capital cost (by about $200/kW). 
Commenter 9780 states in neither competitive market settings nor regulated utility settings are fossil-based EGUs with CCS (or partial CCS) being developed. The absence of investment in EGUs with CCS in competitive market settings indicates that the market judges the costs of CCS to be unreasonable. 
The cost estimates for the final standard of performance are based on recent vendor quotes for the Shell Cansolv technology, the technology currently in use at the Boundary Dam facility.  The cost estimates from these most recent NETL cost studies are consistent with those of other expert techno-economic modelling predictions, and with current vendor quotes and public pronouncements.  See preamble Section V.I.2.
Levelized cost is arbitrary and capricious
Commenter 10098 states EPA's use of a levelized cost of electricity metric is arbitrary, capricious, and contrary to law because it lacks any real-world support, relies on unsupported assumptions to reduce the cost of CSS, and relies on "Nth-of-a-kind" costs when there is no viable "First-of-a-kind" CCS unit already in existence. Commenter 9770 states that the rule's reliance on converting to gas does not acknowledge the amount of natural gas infrastructure that would need to be built to move and store the natural gas in proximity to each power plant and that, when attempting to levelize the cost of electricity in its analysis, the agency did not consider these localized cost factors entirely.
EPA disagrees. With respect to natural gas infrastructure issues are entirely manageable under this rule.  Natural gas pipeline capacity has historically expanded to meet the needs of new natural gas generation capacity, and the same developments will happen in the future.  As the RIA and EPA modeling make clear, expected growth in natural gas requirements is well within historical limits.  The IPM modeling used for the EIA includes a detailed natural gas network connecting power plants to the natural gas system.  (See https://epa.gov/powersectormodeling.)
Commenter 9780 states the LCOE analysis in the Proposal does not satisfy EPA's statutory obligation to assess the costs of CCS because it does not provide complete or accurate information about the costs of CCS with regard to "achieving such reduction" as required by CAA section 111(a). The commenter continues that the LCOE analysis predicts a theoretical, nationalized cost of electricity that would be produced by sources subject to the proposed standards and that EPA cannot deem the costs of partial CCS (i.e., the system of emission reduction that EPA has determined to be best) as reasonable based on an analysis that does not address the direct costs borne by sources that would have to comply with the Proposal. (Commenter provides three reasons for this position.)
Commenter 9423 states that the EPA misrepresents the importance of the levelized cost of electricity (LCOE) data that the EPA uses to justify its claim of economic feasibility, contending that LCOE is not the sole determining factor for companies when deciding what type of power plants to build. Commenter remarks that policy-related factors, such as investment or production tax credits for specific generation sources, can also impact investment decisions. Finally, although levelized cost calculations are generally made using an assumed set of capital and operating costs, the inherent uncertainty about future fuel prices and future polices, may cause plant owners or investors who finance plants to place a value on portfolio diversification. 
Commenter 10098 states that EPA's use of a levelized cost of electricity metric is arbitrary, capricious, and contrary to law because it lacks any real-world support, relies on unsupported assumptions to reduce the cost of CSS, and relies on "Nth-of-a-kind" costs when there is no viable "First-of-a-kind" CCS unit already in existence.  This is exacerbated when calculating the cost of "partial CCS" rather than "full CCS." 
See preamble Section V.I.1.  
Comparison to biofuels production
Commenter 10045 states there is no justification for imposing the costs and burdens of the NSPS, PSD or Title programs on industrial activity emitting Crop-Derived CO2 on account of those emissions. Moreover, those costs and burdens could interfere significantly with the development of beneficial initiatives such as Green Chemistry, cellulosic ethanol, and cost-effective and environmentally sound sewage and wastewater treatment. 
The new source performance standards in this final rule only affect fossil fuel-fired EGUs and are not applicable to other industrial sources such as sewage and wastewater treatment and cellulosic ethanol production.
Comparison of levelized costs and LCOE methodology 
Commenter 10095 states EPA compares the levelized cost of new generation technologies across a range of natural gas prices; however, EPA's analysis  (1) "discards" EIA's high natural gas price forecast; and (2) did not compare new SCPC and IGCC technologies without CUAs to NGCC under a high natural gas price forecast.  Commenter concludes that EPA must recognize, due to historic evidence, that futures outside of those forecasted by EIA are legitimate and likely scenarios and thus show new coal-fired generation technology without CCS as a viable and economic option.  Commenter 9666 states Figure 5-3 of the 2013 RIA reports the levelized cost of electricity generated, using NGCC ($59/MWh) and supercritical coal (SCPC w/o CUA, at $81/MWh), the latter without EPA's climate uncertainty adder (e.g. CUA). Commenter states that adopting an arbitrary cost penalty for CO2 control to use in a study to determine the cost of CO2 control induces bias.
Commenter 10618 states while the LCOE of electricity is often used within the electric industry as a comparative tool, the results of LCOE analysis can be easily biased by incorrect or misleading assumptions, as is the case as presented with the proposed rule.  Underlying the LCOE analysis is EPA's broad assumption that new NGCC units can meet its proposed standard of performance, which is 1,000 lb CO2/MWh of electricity generated on a gross basis. However, one study has indicated that many smaller plants will not be able to meet this standard. If units must be forced to run even if their cost of operation exceeds the power price to meet the efficiency standard, the increased operational cost should be considered in the cost analysis. Commenter continues (10618) that the LCOE also assumes an 85% capacity factor for all technologies being analyzed. This is factually disconnected with how new generation types will operate. Within the U.S., generators typically dispatch on variable cost, with lower cost sources dispatching more frequently. Over the long run, coal generation will dispatch more frequently than gas generation due to fuel costs approximately 50% less (on a MWh basis) than natural gas, as presented in LCOE analysis. Thus, EPA and EIA's assumption that new coal units and new natural gas units will have the same operation and capacity factors is incorrect. Results from broader electric sector modeling could be used to provide the appropriate basis for this number.   Finally, commenter 10618 states the differences in levelized cost between NGCC and SCPC units is dramatically overstated and is particularly compounded by the use of a Climate Uncertainty Adder (CUA) within several of the comparisons, as discussed later in the comments. Therefore, EPA's statement that "it is only when natural gas prices reach $10.94/MMBtu on a levelized basis (in 2011 dollars) that new coal-fired generation without CCS becomes competitive in terms of its cost of electricity" is patently false. Underestimation of NGCC capital and operational costs, overstatement of NGCC operational hours, and overstated operational costs for new coal units make the breakeven number significantly lower.
Commenter 10023 states the problem with using a levelized cost of electricity (LCOE) metric is that it averages the cost of generation over the lifespan of a generating unit and does not account properly for significant differences in upfront capital and related financing costs, which are typically much higher for coal-fired units, especially with the integration of CCS, than for NGCC facilities. Because corporate decisions on generating technologies will be driven in large part not only by an LCOE metric but by upfront financing and capital constraints, EPA erred by not factoring these considerations into its cost analysis.
Commenter 10607 states that because there is no such thing today as a coal-fired power plant with CCS, NETL arrived at its Coal with CCS" cost based on modeling of various systems, and concluded that partial capture (85%) CCS adds only 35% to the cost of an IGCC coal-fired power plant. NETL's value is designed to reflect not the "First of a Kind" application of this technology, but rather its "next commercial offering." But in the one real-world example we have (by definition, the First of a Kind)... there is no actual requirement that Southern Company's Kemper IGCC plant meets this 65% mark; in fact, in awarding a $270 million grant, DOE required Southern to do no more than //design, build and operate" Kemper with the intent of 25% CCS and then //actively work toward" 50% CCS by 2020. Thus, the record does not support NETL's "First of a Kind" cost in light of Kemper, and NETL's methodology for discounting that cost to the "next commercial offering" value cannot support EPA's adoption of NETL's 35% cost premium for CCS.  Conversely, while underestimating the costs of CCS, EPA's reliance on EIA data overstates the costs of nuclear facilities to the private sector. EIA's estimate of $107 /MWhr does not tell the whole story The availability of various incentives, including state or federal tax credits, can also impact the calculation of levelized cost. The values shown in the tables in this discussion do not incorporate any such incentives. 
In the RIA, EPA analyzes the cost differences and potential benefits of different generating technologies under a range of natural gas prices, including prices higher than those observed in the EIA data in the past nearly 20 years. Additionally, these prices exceed even the highest 20-year average levelized natural gas prices projected by EIA in AEO 2014. See RIA Chapter 5. See comments above regarding use of the Climate Uncertainty Adder for cost of SCPC (but note that LCOE used as the basis for the BSER determination, as shown in preamble Table 8, uses no Climate Uncertainty Adder).
Little consistency across groups for calculating LCOE
Commenter 8925 states there is little consistency across groups for calculating Levelized Cost of Energy (LCOE); each entity seems to define differently what is included in LCOE and how it is calculated; and this inconsistency is of sufficient concern that there is an informal international effort to improve consistency across LCOE estimates focused on CCS. Commenter states that EPA runs into this challenge when it takes the cost estimates in Tables 6 and 7 -- which underlie its LCOE analysis -- from different sources and that these analyses should be made consistently. Commenter adds that if put on a consistent calculation basis, commenter estimates that EPA's LCOE for coal with partial CCS would be significantly higher than that of the nuclear technology, rather than about the same as argued in the current analysis. Commenter closes that combining this inconsistency issue with the capacity factor question discussed earlier, the coal with partial CCS estimate appears much more expensive than indicated in EPA's analysis.
Commenter 7977 remarks that the RIA states that the proposed rule will have no changes on EGU business decision-making methodology. Thus, the proposed rule has no costs or benefits based on the assumed LCOE. This assumption creates a false conclusion that no new coal-fired power plants will be built in the analysis timeframe. Independent modeling by the Cabinet establishes this assumption to be robust at levelized natural gas prices up to $8.00 per MMBtu, contrary to the RIA claim of robustness up to $10 per MMBtu. However, the RIA LCOE for SCPC, in Kentucky, is 11. 7 percent higher than independent Cabinet estimates but within 2.5 percent for NGCC estimates. This suggests a bias for NGCC by inflating the LCOE of SCPC as a result of not considering regional cost differences in the LCOE. 
In response to comments maintaining that the LCOE values are derived from different sources which do not use identical methodologies, the EPA notes that the latest publication of the Global CCS Institute "examines the costs and emissions intensities of low emission technologies in power generation.  It uses cost data for the US from a variety of published sources and applies these in a common methodological framework based on the levelised cost of electricity (LCOE) that allows comparison between different technologies in terms of emission reductions."  The estimates for full CCS (the study does not estimate partial CCS costs) are in the same range as NETL and other techno-economic expert cost estimates.  See preamble Table 10.  Nuclear estimates are likewise within the same range of other techno-economic expert estimates.
Cost comparison of other subsidized power to actual costs is inapposite
Commenter 10098 states under Section 111, EPA cannot include general subsidies to the industry in considering the costs of a specific pollution control technology such as CCS. Instead, it must consider the actual costs of the control. Commenter adds that presuming that general subsidies to an industry can offset the costs of control technologies violates the Clean Air Act. Under Section 111, the EPA Administrator must "tak[e] into account the cost of achieving" a standard of performance ("such reduction") through the use of "the best system of emission reduction." 42 U.S.C. section 111(a)(1). In other words, the EPA Administrator must consider the cost of the emission controls, not the costs (and off-setting subsidies) for constructing and operating a stationary source. Thus, the proposed rule's list of subsidies, such as Price-Anderson Act subsidies for nuclear power, domestic oil and gas subsidies, coal exploration and development subsidies, and renewable subsidies, is inapposite. These power sources are unrelated to coal-fired power plants (with the exception of potentially reducing coal costs) and their costs are irrelevant to the cost of constructing and operating CCS and, therefore, cannot be considered under the NSPS.
Commenter 9382 states the selection of IGCC/partial CCS as the BSER also exceeds EPA's statutory authority because EPA did not sufficiently consider the cost of implementing this technology.  All of the four U.S. CCS projects identified by EPA as currently under development have received DOE funding. EPA has not considered the taxpayer-funded portion of these project costs and does not appear to have accounted for cost overruns in its BSER analysis. 15(In addition, the Boundary Dam project recently announced a $115 million cost overrun despite receiving $240 million in funding from the Canadian government).
Commenter 9777 states that EPA, in its discussion of "adequately demonstrated" technology, places significant emphasis on several projects. Observations on costs associated with those projects are set forth in the comments, including the Kemper Project in Mississippi (Kemper) which have seen cost projections rise from $2.4 Billion to over $5 Billion for a 585 MW unit with 65% CO2 capture. Capital cost projections for this project are currently at over $8000/kW.18 (Form 8-K filed by Southern Company and Mississippi Power, April 29, 2014) Mississippi Power was originally to have received a $270 million grant from the U.S. Department of Energy for the project (CCPI Phase 2) and $133 million in investment tax credits approved by the Internal Revenue Service. As of January 2014, the Kemper IGCC project was expected to be online by the end of 2014, past the deadline of May 2014 required to keep $133 million in Federal investment tax credits. The plant's owner has announced it expects to repay the tax credits awarded in 2006. According to information Mississippi Power filed with the Mississippi Public Service Commission (MPSC), customers won't break even with Kemper (much less save money) unless natural gas reaches the price of $12 per MMBtu by 2014 and escalates to $18 per MMBtu by 2035. Even with fluctuations in natural gas prices that result from unusual weather events, prices are predicted to stay below $5 per MMBtu through 2020, according to the EIA. The MPSC is currently considering a rate phase-in plan proposed by Mississippi Power that would keep the rate increase for the first seven years of Kemper operation in the neighborhood of 22 percent. A 2012 study by Brubaker and Associates estimated the rate impacts in the first year of Kemper's operation would be the following:  An average residential customer will see a rate increase of 61%. The estimated annual increase is $912, or $76 per month.  An average commercial customer will see a rate increase of 60%. The estimated annual increase is $4,513, or $376 per month.  An average industrial customer will see a rate increase of 54%. The estimated annual increase is $282,760, or $23,563 per month.22 
Commenter 9777 continues that the Boundary Dam project is a 110 net MW project with 95% carbon capture that requires 21% of the gross MW output to operate and costs an estimated $1.24 billion. This results in a projected capital cost of over $11,000/kW. While this Canadian project is clearly not eligible for U.S. funding, it received $240 million from its own federal government in 2011, of which about $180 million has been spent. As of October 2013, Saskpower says that the project is $115 million over budget. The plant is scheduled to begin operation in the second quarter of 2014. The Texas Clean Energy Project ("TCEP") is a 400 MW gross, 245 MW commercial net output IGCC plant that plans to capture 90% of its CO2 emissions. It has yet to start construction. Originally projected to be operational in 2015, the latest estimates suggest a 2018 start.  Its total project cost is estimated to be $1.727 billion. Capital cost for this project is in excess of $7,000/kW. The DOE share is $450 million (26%). TCEP is also receiving $637 million in investment tax credits from DOE and Treasury Department specially designed to stimulate clean coal electricity projects on competition of the project. The DOE awarded $350 million in December 2009 for an eight-year joint project with University of Texas Bureau of Economic Geology. TCEP also received an additional $100 million from the American Recovery and Reinvestment Act ("ARRA)" in August 2010. TCEP received the $450 million award in 2010 from the DOE's CCPI. All government funding is through the ARRA. Because the CPS Energy purchase agreement with Summit Power was not renewed prior to its expiration at the end of December 2013, the project's ability to secure necessary financing for the project may be jeopardized. Given that all of these projects required a government subsidy to initiate, and recognizing that costs continue to grow, tax payers and energy consumers will endure substantial cost without confidence of either long-term viability or benefits to global climate.28 All of these EPA selected projects' projected capital costs are at least two to four times the proven capital cost of the recently completed AEP Turk ultra-supercritical pulverized coal plant which was completed at $3,000/kW. 
Commenter 9600 states only one project cited by EPA, the Edwardsport IGCC facility, which is not even a FOAK employing carbon capture, is even operational and operating less than one year at that. Two other projects cited by EPA, TCEP and HECA are barely off the ground with operation planned no earlier than 2017 and 2018 respectively. Commenter adds that the Kemper project is not expected to be operational until the end of 2014, so at this point no facilities cited as FOAK are completed and most are years away from it, and obviously no operational data are available to gauge facility eventual costs, reliability and availability. 
Commenter 9600 continues that  EPA's LCOE data used to justify that partial carbon capture technology in the "next commercial offering" will be reasonably priced do not comport with actual cost data associated with existing projects including those that are receiving funding under DOE's clean coal demonstration program. 
Commenter 10046 continues, stating EPA points to Kemper, the Texas Clean Energy Project, and the Hydrogen Energy California Project, although we would point out that only Kemper is in a position to provide evidence that a segment of the industry is accommodating CCS costs, since it is under construction. The other two facilities may never even reach the construction phase. EPA then points out that each of these facilities is receiving substantial DOE and other funding, but then ignores that subsidy. Commenter states that industry is not accommodating the costs of partial CCS; it is accommodating some of the costs of partial CCS, with the rest of the costs being accommodated by federal and state government in the form of financial support. EPA must revise this conclusion, based on the evidence presented, to support only the proposition that a segment of the industry finds some of the costs of partial CCS to be reasonable because they are accommodating them or have announced plans to attempt to do so. Similarly, EPA neglected to point out that each of these projects is relying on revenues from EOR.
Commenter 10046 states EPA also lists three IGCC units, the Kemper plant under construction and two other planned projects under development. EPA labels the planned projects as being in advanced stages of development, noting that both continue to move forward but EPA provides no further information to support its assumption that these plants will move forward, and if they do, that the necessary learning will be achieved. Commenter concludes this is simply too thin of a record to reasonably support the level of cost reductions EPA assumed in its numbers. 
Commenter 10607 states EPA's proposed regulation requires the use of partial capture CCS technology for new sources to be able to meet the emission standard. Based on the most recent cost data associated with the Kemper and Edwardsport projects, the cost of installing and operating partial CCS is exorbitant, and therefore unsustainable as the basis of a BSER determination. In the two demonstration projects relied upon by EPA, the actual costs were much higher than the original cost estimates. The Edwardsport plant resulted in significant overrun costs of approximately $835 million, for a total project cost of $3.5 billion. It is important to note that a settlement agreement between Duke Energy and the Indiana Office of the Utility Consumer Counselors resulted in a "Hard Cost Cap" of $2.595 billion for Indiana ratemaking purposes. Therefore, Indiana rate payers will shoulder the burden, considering that Duke Energy is responsible for the overrun costs of $900 million. Currently, overrun costs at Kemper are estimated to be greater than $1.1 billion above the original estimate of $4.75 billion for the project. In a settlement agreement with the Mississippi Public Service Commission, Mississippi ratepayers are responsible for $2.4 billion of the plant's costs in traditional rates. 
Commenter 10607 states EPA discusses federal funding for CCS, and concludes that "the availability of these governmental subsidies supports the reasonableness of the costs." But EPA offers no specific numbers for the amount of this support, aside from $1.2 billion apparently still available from DOE for some limited period of time. EPA's conclusion that "a section of the industry is already accommodating the costs" of CCS is based on demonstration projects that receive DOE financial assistance. "DOE [ ... ] has committed $2.2 billion for 5 projects to date." Commenter remarks that it is unreasonable to conclude that the costs of CCS are not exorbitant under circumstances when such funds are limited and will not be available indefinitely.
Kemper cost overruns reflected highly questionable strategic decisions (virtually build first, design later0 that are not generally applicable. Edwardsport does not even operate CCS, as the commenter notes, so cost issues there have literally nothing to do with CCS.  CCS at Boundary Dam came in at budget, on time, and is operating highly reliably.  See POWER magazine, Aug.1, 2015 (awarding Boundary Dam its power Plant of the year award).
Natural gas capacity factors uncertainty
Commenter 8925 states in its Levelized Cost of Energy (LCOE) analysis, EPA assumes an 85% capacity factor for both new NGCC and coal technologies.  This would represent a dramatic departure from historic capacity factors for natural gas.  In 2012, when natural gas prices hit historic lows, the average NGCC capacity factor in the US was 52%; since 2008, it has been in the 40-50% range.  When gas prices were high (e.g., 2005), it dipped into the 25% range in some regions of the US.  Capacity factors for new coal have traditionally been much higher, greater than 70%. Future capacity factors are highly uncertain since they are strongly dependent on the generation mix.  As existing coal units retire and are replaced by gas units, the capacity factors of new gas plants would likely increase.  However, as renewable energy achieves greater deployment, the capacity factor of these new gas plants would likely decrease, assuming the load growth continues to be slow. Thus, if historic capacity factors are assumed, the future LCOE cost gap between gas and new conventional coal that EPA uses, in talking about the dominance of gas, is likely much smaller than depicted.  This is especially true for generation technologies deployed in the 2014-2022 analysis window.  If the CUA is removed, the LCOE of conventional coal decreases from $92/MWH to $81/MWh, and if a 50% capacity factor were used for NGCC, versus the 85% capacity factor assumed by EPA, the LCOE for NGCC would increase approximately $10/MWh to $69-86/MWh, creating a much different comparison.  Given regional variations in the fuel and technology costs, the current gap in LCOE would likely not cause NGCC to eliminate new conventional coal (or coal with CCS) from future generation forecasts. EPA also assumes 85% capacity factors for coal with CCS and for new nuclear when comparing their costs.  Nuclear has very low variable costs and has historically had capacity factors of more than 90%.  Coal with CCS, on the other hand, has variable costs much higher than conventional coal, could easily have variable costs greater than natural gas combined cycles and "given no proposed limits or price on CO2 emissions" could realistically have a capacity factor of well below 50%.  Spreading the large capital costs of coal plus CCS over many fewer hours would significantly increase its LCOE (e.g., using public EPRI cost data, if pulverized coal with CCS at an 85% capacity factor costs $120/MWh, assuming the same underlying costs and a 50% capacity factor would increase the cost estimate to over $170/MWh).  Thus, it is important to consider likely capacity factors when comparing the LCOE's of technologies. 
The EPA specifically indicated that it was comparing technologies that could be utilized to supply base load power generation. We specifically wanted to compare costs of generating options providing the same service. See preamble section IV.B.1  -  "A key means of assessing the reasonableness of cost at proposal was comparison of the levelized cost of electricity (LCOE) with that of other dispatchable, base load non-NGCC generating options." In evaluating the costs in Table 8 of the preamble we note that "This final standard reflects the level of emission reduction achievable by a highly efficient SCPC implementing the degree of partial CCS that remains cost comparable to the other non-NGCC dispatchable base load generating options." In this comparison of base load options, to assume that new generating technologies that are built for the purpose of supplying base load power would, instead, operate at historical capacity factors is not logical. We are not assuming that new units will operate at historical capacity factors because, as we note in the preamble  -  "the power sector is undergoing significant change and realignment in response to a variety of influences and incentives in the industry" and assuming historical capacity factors would not seem to acknowledge that significant change and realignment. While commenters believe that EPA's modeling assumptions disadvantage coal, in fact the modeling matches the reality of the real world. Between 2000 and 2013, approximately 90 percent of new power generation capacity built in the U.S. has come in the form of natural gas or renewable energy facilities.
Comparing coal-fueled power sector to nuclear power inappropriate
Commenter 10036 states EPA's approach to determining reasonable costs is flawed because EPA's test of industry survival is not met, identifying EPA's acknowledgement that typical new coal-fueled power plants with partial CCS are not competitive with new natural gas combined cycle (NGCC) units and stating that EPA bases its determination that the coal-fueled power sector can survive on comparing its costs to those of the nuclear power industry. Commenter explains no new nuclear power plant has entered service in the U.S. since 1996, and the core of the nuclear power plant manufacturing sector has left the U.S. EPA projects no new coal units with partial CCS will be built in the U.S. throughout the projection period for the rule's analysis. That projection reflects a cost that is "greater than the industry could bear and survive."(EPA defines a "reasonable cost" to be one "greater than the industry could bear and survive", language taken from the decision in Portland Cement Ass'n v. EPA, 513 F.2d 506, 508 (D.C. Cir. 1975), see 79FR1464, January 8, 2014) 
Commenter (10036 states with corrections to EPA's analysis to reflect a consistent LCOE methodology for coal and nuclear, and inclusion of the nuclear PTC, the comparison of coal to nuclear based electricity costs becomes $128/MWh for coal, versus $94.3/MWh for nuclear. Commenter continues, stating coal partial CCS is 36% more expensive than nuclear. This difference is greater than the 27% difference between the costs of IGCC with 90% CCS and nuclear in EPA's cost assessment, which led EPA to reject IGCC with 90% CCS as too expensive to qualify for BSER. 
Commenter10046-7034 further remarks  that what the company may or may not want to build, or what it includes in its IRP, has nothing to do with what might get built because that is within the province of state public utility commissioners. If they do not approve a new coal plant, then a new coal plant will not get built: An IRP compares multiple alternatives, and examines the costs, reliability, and environmental impacts of each. The utility will use the results of the IRP to decide what types of resources to acquire, whether it's better to own power plants or buy power from others, and how to manage its programs to achieve the desired results. The regulator may use the IRP to determine what investments the utility may make, and it should use the IRP as one tool in evaluating the prudence of the utility's actions over time. However, simply including a proposed resource in an IRP (whether approved or merely accepted by the regulator) does not necessarily make it prudent or confer pre-approval, nor does it excuse the utility from continuous re-examination of proposed projects in light of such factors as changing loads, changing costs, and emerging alternatives. Hence, public utilities commissions, not utilities, are the relevant audience from which EPA needs to derive.
When the technology is already not price-competitive but is being considered for reasons unrelated to cost such as preserving fuel diversity and hedging against rising prices of other fuels, then it is legitimate to compare costs of non-NGCC baseload dispatchable technologies.  See generally preamble section V.I.1.  Further, as documented in preamble section V.H.5.b and the IRP TSD, developers are considering new nuclear capacity.  

The commenter's assertion that "EPA projects no new coal units with partial CCS will be built in the U.S. throughout the projection period for the rule's analysis" and that under Portland Cement II this means that the rule reflects a cost that is "greater than the industry could bear and survive" is a significantly flawed syllogism.  First, the RIA projects that no non-compliant coal capacity will be built in the review period, but that some coal with CCS will be.  See RIA table 4-1.  Second, this rule relates solely to new coal capacity and so obviously does not affect the existing coal fleet, so the rule cannot have the industry-wide consequences the commenter projects.  
Full versus partial CCS - comparison to nuclear power: LCOE estimation approach merits examination
Commenter 10036 states EPA concluded that the LCOE of full CCS ($136-147/MWh) was not comparable to nuclear ($103-114/MWh) and therefore presented an unreasonable cost that eliminated full CCS from consideration as BSER. In contrast, EPA concluded that the LCOE of partial CCS ($109-110/MWh) was similar to nuclear, so partial CCS has a reasonable cost. Setting aside commenter's above-stated objections to the use of nuclear power cost as a measure of acceptability, the approaches used to generate these LCOE estimates merit examination. (See additional detail in comment.)
Commenter 9194 states that EPA must show that BSER is "adequately demonstrated" and "achievable" at the source level at reasonable cost.  Commenter explains that EPA is attempting to expand the standard of evaluation from a source category to a system of generating electricity and that EPA indicates they are applying standards to electric generation and electric supply, not source specific technologies as the CAA suggests is appropriate. In doing this, commenter contends that EPA inappropriately compares the costs of coal with CCS with nuclear and biomass plants. Commenter states that EPA must compare BSER for coal with coal technology, and BSER for natural gas with gas technology.
Commenter 10046 states furthermore, during the eight-year regulatory window applicable to the proposal, nuclear units are not a generally available base load technology. Only Summer and Vogle can be expected to come on-line in this period. Consequently, EPA's first argument in support of economic reasonableness does not stand. Instead, it actually proves that, relative to the segment of the industry EPA was considering, partial CCS is also economically unreasonable because it cannot compete under a low carbon metric with the cost of new nuclear. EPA also posits that the costs of CCS are reasonable for 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. EPA cited nothing to support its proposition that customers have expressed willingness to pay for higher-cost generation such as coal with partial CCS, nor did EPA cite any evidence to support its conclusion that demand for electricity might be price inelastic in some cases. While we agree that many companies have quite properly expressed a preference for new coal plans as a mechanism to maintain fuel diversity and blunt EPA's enforced dash to gas, the conclusion that a new coal plant would be constructed despite the cost is economically incoherent.  Commenter10046 remarks  that what the company may or may not want to build, or what it includes in its IRP, has nothing to do with what might get built because that is within the province of state public utility commissioners. If they do not approve a new coal plant, then a new coal plant will not get built: An IRP compares multiple alternatives, and examines the costs, reliability, and environmental impacts of each. The utility will use the results of the IRP to decide what types of resources to acquire, whether it's better to own power plants or buy power from others, and how to manage its programs to achieve the desired results. The regulator may use the IRP to determine what investments the utility may make, and it should use the IRP as one tool in evaluating the prudence of the utility's actions over time. However, simply including a proposed resource in an IRP (whether approved or merely accepted by the regulator) does not necessarily make it prudent or confer pre-approval, nor does it excuse the utility from continuous re-examination of proposed projects in light of such factors as changing loads, changing costs, and emerging alternatives. Hence, public utilities commissions, not utilities, are the relevant audience from which EPA needs to derive evidence to support its conclusions: The result of this [IRP] planning process is a utility plan to build or acquire new generating or demand-side resources to serve bundled loads. This plan is typically informed by a stakeholder process and then filed with the state regulators, who rule on the prudency of utility investments and decide which costs are allowed to be collected through retail rates. With one exception, these commissioners have not, to date, shown any appetite for new coal CCS power generation that is almost double the cost of new gas. That one exception is Kemper - but even West Virginia specifically rejected AEP's request to construct a large-scale CCS retrofit project because of economic and policy conditions. Although EPA's proposal would generate a policy condition (i.e., obligatory partial CCS), it does not address the associated economic conditions, and it is not plausible to suppose that West Virginia would approve a new partial CCS coal plant when it can build a new gas plant for about half the cost.
Commenter 9190 states EPA does not consider the probability of significant price increases. EPA's NSPS policies will have a profound effect upon not only the domestic electricity markets but also many sectors of our economy that rely upon natural gas. As the Department of Energy's National Energy Technology Laboratory (NETL) has warned "policies that encourage the use of natural gas to substitute for coal in power generation could very well lead to spectacular price increases for households and industry." Indeed, according to NETL, coal-based electricity restrained the price of electricity and prevented the price of natural gas from matching the rise in the price of oil. EPA's NSPS proposal will change all of that-and for the worse. Nothing in EPA's proposal demonstrates that the agency has performed a reasonable assessment of the impacts of this rule upon the vast number of economic sectors that rely upon reliable and competitively priced electricity and natural gas.
Commenter 10607 states EPA's economic rationale in September 2013 (and again in January 2014) is that coal plants with CCS cost about the same as new nuclear power plants, and because five new U.S. nuclear units are under construction, this means that "the cost of new coal-fired generation that includes CCS is reasonable today." EPA uses the NETL figures for coal plant CCS costs and the Energy Information Administration's (EIA) figures for nuclear plant costs (on the grounds that NETL's nuclear costs "Were not available or sufficiently recent").  According to EPA, NETL's cost for IGCC coal with partial CCS is $109/MWhr; when combined with the sale of captured CO2 for Enhanced Oil Recovery ("EOR" that cost is reduced to between $97 and $101/MWhr, depending on the price of CO2. EIA's comparable cost for nuclear is $107.28 
Commenter 10046 disputes the relevance of Integrated Resource Plans (IRPs) to the EPA's conclusion that nuclear is a potentially available non-NGCC base load dispatchable technology, and to the further conclusion that costs of the final standard of performance are reasonable because they are comparable to those for new nuclear capacity.  The commenter maintains that only Public Utility Commissions decide what gets built.  The commenter, and also commenter 10036, questioned comparing LCOE of fossil fuel-fired steam generating units with nuclear at all.

The commenter is of course correct that IRPs are not determinative of what capacity will be built.  See preamble section V.H.3 making the same point.  Nonetheless, IRPs are not meaningless, and statements in IRPs are relevant indicia of utilities' future intentions.  States require utilities to prepare IRPs, and take IRPs into account in their own deliberations and determinations.  See generally IRP TSD.  Documents that are legally mandated and play a role in state PUC determinations are hardly irrelevant, and the EPA can thus reasonably look to IRPs of indicia both of what utilities are planning, and what state PUCs are considering.  As shown in the IRP TSD and preamble section V.I.1, new nuclear technology is mentioned as a possible technology in various IRPs, a legitimate indication that new nuclear capacity remains a viable possibility.  Further indicia that new nuclear capacity is possible are actual construction of new nuclear capacity in recent years (Vogtle Electric Generating Plant, Watts Bar Generating Station).  The leading technical economic journals likewise continue to view nuclear as a viable future technology.  See, e.g. Global CCS institute, "The Costs of CCS and Other Low-Carbon Technologies (2015 update) at 1 ("[n]uclear generation plant ... can also be cost competitive in some markets given [its] high utilization rates (i.e. can be operated up to 80 to 90 per cent of the time)").
Comparing coal-fueled power sector to biomass and geothermal technologies, along with other renewables, inappropriate
Commenter 10036 states biomass and geothermal are inappropriate technologies for a base load technology cost comparison, stating that together they contributed less than 2% of electric utility generation in 2012, and adding that wind and solar technologies are non-dispatchable intermittent resources. Commenter notes DOE/EIA states it is not appropriate to compare costs for non-dispatchable, renewable energy sources to dispatchable systems like coal and nuclear generators ("their levelized costs are not directly comparable to those for other technologies"). Commenter continues that EPA, in effect, states that, even if the nuclear comparison doesn't justify partial CCS as reasonable, a biomass comparison does, and even if a biomass comparison fails, EPA seems to believe it has the discretion to not apply the "greater than the industry could bear and survive" language in Portland Cement Ass'n v. EPA and instead rely on more ambiguous language from case law, or essentially to deeply discount the cost criterion altogether. Commenter states EPA must consider the statutory criteria for establishing BSER and relevant findings in case law that conflict with the agency's policy position.
Commenter 9497 states renewable options simply are not feasible for large-scale generation in Mississippi. Biomass is the primary renewable energy option in Mississippi, although economic issues present hurdles to using biomass as a primary energy source. In 2010 Mississippi generated 2.8 percent of its electricity from renewables, and nearly all of this generation was from wood and wood waste. The Commenter, as a policymaking body, must take the historical volatility and uncertain future circumstances into consideration when it evaluates the state's increasing reliance on natural gas as a primary fuel source. Figure 2 charts natural gas prices since 2002, illustrating the substantial volatility in base commodity prices (i.e., prior to additional costs for delivery to plant) over the past decade, and even to the most current data. From the recent monthly low in April 2012 to January 2014, the average natural gas commodity price rose by more than 140%. It is worth remembering that during the recent period of high natural gas prices in the mid-2000s, many utilities began planning new coal-fired power plants, several of which have gone into service in the past several years. We are not far removed from that period, and gas price volatility continues.
Commenter 10046 states that an erroneous cost analysis is found in the TSD, where EPA states that partial CCS is also competitive with biomass-fired generation, which is another generation technology often considered for low carbon base load power. In fact, that technology is not now and will not be during the eight-year period covered by the pending proposal an available source of meaningful base load generation. Biomass demonstration has gone furthest in Britain, where the government cap on such projects has been recently reduced by 90 percent amid project cancellations by the utility companies RES, E.ON, and RWE. The inefficiencies of wood-burning probably doom this technology for base load purposes over any time period. NETL's point is that the cost reductions that EPA included in its cost estimates derive from learning by doing, which requires that actual doing, in the form of construction of new CCS systems, occurs, and that these lessons be shared. NETL states: The single value, next-of-a-kind costs EPA used represent the expected costs after significant learning and demonstrations have taken place. 
Commenter 10036 states EPA, in effect, states that, even if the nuclear comparison doesn't justify partial CCS as reasonable, a biomass comparison does. And even if a biomass comparison fails, EPA seems to believe it has the discretion to abandon the "greater than the industry could bear and survive" language in Portland Cement Ass'n v. EPA and rely on more ambiguous language from case law, or essentially to deeply discount the cost criterion altogether. EPA lacks the discretion either to disregard the statutory criteria for establishing BSER, or ignore relevant findings in case law that conflict with the agency's preferred policy position.
The primary comparisons for new dispatchable base load generation options were NGCC, coal without CCS, coal with varying levels of CCS, nuclear, and biomass. We did not compare with geothermal in the final standard.  We do note (see preamble footnote [276] that notes: "Table 8 includes LCOE figures for biomass-fired generation, a potential sources of dispatchable base load power that is not fueled by natural gas. The EPA includes this information for completeness, while noting that biomass-fired units in operation in the U.S. are smaller scale and thus are not as robust analogues as nuclear power." So, while we provide cost ranges for new biomass-fired EGUs, we clearly focus our comparison on new fossil options and nuclear.
Next of a Kind (NOAK) costs in inappropriate
Commenter 10098 states EPA disregards the track record of deployment of CCS at coal-fired power plants and as part of Department of Energy's R&D projects in stating "it is reasonable to focus on the next-of-a-kind costs provided in Table 6".  Commenter adds as the D.C. Circuit noted, "[s]ince the standards here put into effect will control new plants immediately, as opposed to one or two years in the future, the latitude of projection is correspondingly narrowed" and continues that, EPA is not projecting out one or two years in the future, but likely several years, if not decades, given the propensity for project delays and the Department of Energy's goal to begin demonstration projects by the year 2020. The Commenter concludes EPA's refusal to consider the current costs of CCS is unlawful. Commenter (10034) states EPA should commit to measuring whether its standard has any implementation cost, and, if so, whether these costs follow the pattern of EPA's estimate for "next-of-a-kind" plant costs.
Commenter 10036 states EPA's approach of basing costs on "Next-of-a-kind" (NOAK) projections is impermissible because the regulations apply immediately, to any unit commencing construction after January 8, 2014, and because no approach for achieving commercial-scale CO2 reductions at a coal-fueled power plant has reached "First-of-a-kind" (FOAK) status. (Commenter discusses units under construction and their unique designs and costs.) Commenter continues, stating new units which have designs needing initial demonstration have costs that are more than twice the cost assumed by EPA, and EPA is assuming that the cost for NOAK units that do use the same technology as a FOAK demonstration unit will have a capital cost reduction of over 50% but commenter believes that such a cost reduction assumption is unreasonable. 
Commenter 10044 states that EPA has improperly used the "next of a kind" cost estimates when it should have used "first of a kind" cost estimates for the cost of electricity estimates for power generation with and without carbon capture systems. Commenter states that in its Technical Support Document, EPA redefined "next of a kind" and should present a full discussion of its costing methodology and any reasons why it should ignore the "first of a kind" costs in its analysis, or otherwise incorporate the "first of a kind" costs into a revised cost analysis. 
Commenter 9487 states if CCS were technically feasible, the costs of the proposed NSPS are extraordinary, CCS costs for new coal-fired power plants are underestimated, EPA does not consider "first of its kind" costs (FOAK) although no full-scale operational CCS system at a coal-fueled power plant exists in the U.S. Commenter adds that when evaluating increased costs and risks, pilot CCS and experimental projects are irrelevant because these projects have been government subsidized, and regulatory hurdles and risks are likely undervalued and potential revenues from CO2 waste stream sales for possible use in enhanced oil recovery (EOR) fields are overvalued.
Commenter 9600 states it is ironic that EPA uses a few demonstration CCS projects as FOAK projects to then conclude that next projects can be evaluated at "next commercial offering costs," when it does not use actual cost data associated with these first project costs.  Commenter 9600 continues that the contention that based on these early projects the next-of-a-kind coal-based EGUs with partial carbon capture will somehow even approximate the LCOE data in Table 6 is not only arbitrary but totally meritless and states that there is no data in the rulemaking docket to support the contention that Table 6 LCOE costs are reasonable projections of next-of-a-kind project costs based on actual costs associated with the projects that EPA cites as FOAK.
Commenter 9600 states studies are too unreliable and speculative to be used to reasonably determine the state of technology and associated costs of carbon capture, explaining that according to the DOE studies of which EPA relies, the margin of error of the derived LCOE data ranges from -15 to + 30 percent. Commenter concludes that this wide margin of error makes any chosen LCOE costs within this wide range arbitrary. Commenter states that For Table 6 costs, EPA has chosen the midpoint from the data extrapolated from these studies for its LCOE predictions but even at that midpoint level, the LCOE for SCPC EGU with partial carbon capture is 20 percent above a SCPC EGU without carbon capture, and this increase is well above any level determined to be judicially permissible, as EPA recognizes in Portland Cement 486 F.2d. 387, where only a 12 percent capital cost increase was a level considered permissible. Commenter continues that EPA cannot reasonably rely on Table 6 LCOE data that are based the theory that as technology matures with the construction of successive plants, the cost decreases. Since BSER must be available "immediately" and at a reasonable cost, the very next coal-fired EGUs must to able to install and operate partial carbon capture at costs that are deemed reasonable. The proposal describes the Table 6 LCOE data as the product of "learning by doing" where it is assumed the very the next EGU that incorporates carbon capture would have a LCOE costs as represented in Table 6. But even where eventual costs do in fact decrease over time after successive generations of technology development, costs for next generation may not decrease at all, but may in fact increase. Commenter states that for either full or partial carbon capture, technology adjustments, increasing material and labor costs, and unforeseen intervening factors can significantly inflate what the proposal describes as LCOE for a "next commercial offering" or a "next of a kind" facility, and commenter says that one need not look any further that the nuclear power side of the electric industry to recognize intervening factors made nuclear power, once thought by some that successive generations of unit development would eventually make nuclear power electricity costs too cheap to meter, the most expensive form of base-load electric generation today.  Further, commenter remarks that even assuming EPA's theory that the cost of carbon capture will decrease with additional technology application is valid, cost decreases may not occur with each successive facility such that any successive project may or may not be less costly and maybe more costly that the previous one.
Commenter 10046 states that EPA misrepresented the costs of partial CCS, and disregarded the fact that what EPA deems to be economically unreasonable CCS costs are within the predicted range of partial CCS. During interagency review, commentators from NETL, whose costs EPA used to assess the economic reasonableness of CCS, made three key comments. First, NETL argued that the costs provided were a range, and EPA used the low end of the range, thereby misrepresenting the cost estimates. Second, NETL argued that EPA should not use NETL's next-of-a-kind costs, but rather its FOAK costs. Third, NETL argued that costs would not be lowered to approach next-of-a-kind costs unless more demonstration projects are completed. We agree with each of NETL's comments, and believe they establish that partial CCS is economically unreasonable. The NETL-recommended costs that EPA uses are set forth in the table.
Commenter 10046 states that a cost value considered unreasonable by EPA falls well within the range of the NETL CCS costs. As NETL noted in its comments, and as stated in the NETL cost studies upon which EPA relies, the costs estimates have an expected accuracy range of -15%/+30%. As the NETL studies note, this accuracy range is consistent with the feasibility study level of design engineering applied in the studies. The accuracy range is derived from the industry standard developed by the Association for the Advancement of Cost Engineering (AACE), and applied to feasibility studies of the type NETL is undertaking. AACE specifies that the -15%/+30% accuracy range provides an 80% confidence level that the actual cost will fall within the bounds of the low and high ranges. The relevance of the cost ranges is well understood. Cost estimates necessarily are reduced to a single cost value, so a number can be used: An estimate is a prediction of the expected final cost of a proposed project. . . . By its nature, an estimate involves assumptions and uncertainties, and is therefore associated with some level of error. We can correlate this level of error and uncertainty to probabilities of over-running or under-running the predicted cost. So given this probabilistic nature of an estimate, it should really not be regarded as a single point number or cost. Instead, an estimate actually reflects a range of potential outcomes, with each value within this range associated with a probability of occurrence. 
Commenter 10046 states in assessing costs for full capture, EPA concluded that a $136/MWh cost for IGCC units exceed what project developers have been willing to pay for other low GHG-emitting base load generating technologies (e.g., nuclear) that also provide energy diversity. For that reason alone, we do not believe that the costs of full implementation of CCS are reasonable at this time. But when the NETL probability range is applied, IGCC at 25% capture has a cost range of $112 to $146/MWh. Supercritical pulverized coal (SCPC) units at 40% capture have a cost range of $110 to $143/MWh. Hence, a cost EPA pegged as economically unreasonable ($136/MWh) is well within the predicted cost range provided by NETL for both IGCC and SCPC units, at an eighty percent confidence level. Consequently, EPA cannot plausibly conclude that IGCC with partial capture is economically reasonable based on its own assessment because it is equally likely as not that the unreasonable cost numbers contained in the range are the true numbers. Hence, EPA has produced an analysis under which the true cost is as likely to be unreasonable as not. 
Commenter 10046 states EPA also established a much lower number than $136/MWh as unreasonable. EPA's conclusion that $136/MWh is economically unreasonable is based upon what project developers have been willing to pay for other low GHG-emitting base load generating technologies (e.g., nuclear) that also provide energy diversity. EPA uses the cost of new nuclear ($103 to $114/MWh) as the benchmark from which to compare what project developers have been willing to pay. Hence, by EPA's own reasoning, anything above $114/MWh is economically unreasonable, not merely numbers above $136/MWh. Using that EPA-selected cutoff, the vast majority of cost numbers from the NETL cost range exceed a cost EPA considers unreasonable. Clearly, $115/MWh is well at the lower end of both the SCPC cost range ($110 to $143/MWh) and the IGCC cost range ($112 to $146/MWh). Thus, it is patently unreasonable for EPA to conclude that the costs for partial CCS for either unit type are economically reasonable.  To compound EPA's difficulties, NETL did not even recommend that EPA use the NETL next-of-a-kind numbers, but rather the FOAK cost numbers for CCS. NETL argued that the next-of-a-kind numbers EPA used represent the expected costs after significant learning and demonstrations have taken place, concluding [t]his learning hasn't occurred yet. When EPA refused to present both the full range of costs as well as the recommended FOAK costs, NETL observed we believe current cost of CCS is not accurately represented. As can be seen from the NETL table provided above, if EPA were to use the recommended FOAK costs, then none of the costs in the cost range would be considered economically reasonable because the lowest end of the FOAK cost ranges are $121/MWh (SCPC) and $129/MWh (IGCC), well above the EPA's established cutoff of $115/MWh.
Commenter 10046 states the FGD-CCS case study conducted by UKERC supports NETL's position. That study concluded: It is a difficult thing to foresee all cost drivers of a technology before it is mature, for example the difficulties of transferring technology and expertise from other sectors. There is need to be skeptical of current cost estimates for CCS, produced before there is even one large scale, integrated CCS system. Cost rises and unforeseen technical problems emerging can be expected, even after the first large scale systems have come on line.  Claims that we are on a learning curve, with costs likely to go down in the near term are not plausible. Hence, at least two independent and expert organizations would strongly disagree with EPA's conclusion that it is reasonable to use NETL's next-of-a-kind cost figures to assess the economic reasonableness of CCS. But EPA has an additional problem because the very plants EPA needs to justify its assumption that significant learning will occur are not even under construction, but rather are in speculative planning stages. Currently, two plants are under construction: one is an IGCC unit in the United States, and the other is a post-combustion capture system in Canada. Two more units are in planning stages and might get built, although recent history tells us that planned CCS projects are far more likely to be cancelled than to actually proceed. EPA's own RIA analysis, which constitutes EPA's facts found, does not contemplate any new CCS units coming on-line after 2015. Thus, the total possible pipeline from which EPA can support a learning by doing cost reduction comes exclusively from these four plants, two of which might not get built. That is unreasonably thin gruel to support a learning by doing cost reduction. EPA's assumed learning by doing cost reductions are represented as fact in its cost projections, but rely on events that have not occurred and may never occur. 
Commenter 10046 states EPA's assumption that new plants will be constructed to fill in the learning curve necessary to support its use of next-of-a-kind costs is unreasonable. EPA's economic analysis does not predict that the plants will provide the significant learning NETL states is needed before EPA's numbers are plausible estimates. It is also a fact that cancellation of planed CCS projects is the rule and not the exception. Although EPA may make a prediction on how control technologies may develop in the future, that prediction must be reasonable and well-supported. At minimum, EPA must address two key questions before it can plausibly rely on these planned projects as proving support for the already baked in learning by doing cost reductions. First, what evidence does EPA have that these projects will be proceeding, and why is that evidence relevant EPA provides no TSD or other information that gives any real indication as to whether these projects will in fact proceed. Nor does EPA discuss why it believes these projects will go forward while others have not, what factors it looked at to conclude that the projects will proceed, and why all of this information provides a reasonable basis for EPA's key assumption that these projects will proceed. Commenter states EPA did not provide any of this analysis; it simply provided a list.
Commenter 10046 states EPA must explain why it believes that at most two or maybe three more projects beyond the two currently under construction are reasonably likely to provide the significant learning. Learning-by-doing is not a line on a graph; it is a process that actually occurs or does not. For such learning to occur, initial plants must be completed, and the lessons learned therefrom shared with and absorbed by others. This does not always happen. For this to occur, the technologies for the next plants need to be the same as the initial plants. If they are different, then no learning results. Additionally, the vendors must generally be the same, since vendors do not readily share information. Further, the projects must be sequenced in time so that lessons can be shared, which seems unlikely to occur with EPA's projected plants. EPA suggests its new plants are in advanced stages of development, a point that is well past the design stage, and a point where it would seem unlikely that those plants could learn anything from the two now under construction.
Commenter 10046 states experts agree that costs are unlikely to drop early in the technology development process, and indeed could rise above FOAK costs in the short term. In the case of FGD, costs rose substantially from the initial plant through the 1970s as additional plants were built. Indeed, both capital and operational expenses as well as maintenance costs rose by about a factor of five from 1968 to the late-1970s. Thus, the capital costs for FGD started at six percent in 1970 and rose to around 20 percent ten years later, even though several dozen units were built. Key technical problems were ultimately resolved and costs ultimately came down, but only after a decade of plant construction and a decade of learning. NETL's learning-curve analysis also makes clear that cost reductions do not always begin with the second plant. In the face of these uncertainties, EPA proffers only a guess as to the number of new CCS plants that will be built, and an unsupported assumption that these new plants will occur in ways that produce meaningful learning by doing. For these reasons, EPA's use of next-of-a-kind cost figures is the type of unreasonable and unsupported crystal ball inquiry that courts have overturned.
Commenter 8971 states USEPA's cost estimates in the CO2 NSPS show that partial capture CCS increases the levelized cost of electricity by nearly 20% for a supercritical pulverized coal unit. 79 Fed. Reg. 1476. These cost estimates understate reality, because they are based on "next of a kind" not "first of a kind" costs. There is no possible justification for the use of next of a kind costs when no facility yet exists. Commenter continues that even if the cost estimates that USEPA relies on were accurate and appropriate, those costs are still not reasonable and are excessive. The Department of Energy describes CCS technologies as "not ready for implementation on coal-based power plants because they have not been demonstrated at appropriate scale, require approximately one-third of the plant's steam and power to operate, and are cost prohibitive." A technology that is cost prohibitive cannot also be reasonable.
Commenter 10788 states that fuel diversity is important to their operations and future resource planning needs and that EPA's "levelized costs" analysis is flawed as detailed in other comments and also does not account for the direct value of fuel diversity.
Commenter 9407 states that EPA cannot reasonably rely on Table 6 LCOE data that are based the theory that as technology matures with the construction of successive plants, the cost decreases. Commenter also notes that  even assuming EPA's theory that the cost of carbon capture will decrease with additional technology application is valid, cost decreases may not occur with each successive facility such that any successive project may or may not be less costly and maybe more costly that the previous one. The proposal and information contained in the rulemaking docket provide no rationale explaining how EPA arrives at these specific Table 6 LCOE predictions. Commenter 9407 continues that  EPA's LCOE data used to justify that partial carbon capture technology in the "next commercial offering" will be reasonably priced do not comport with actual cost data associated with existing projects including those that are receiving funding under DOE's clean coal demonstration program. Commenter states that as the Enclosure 2 Cichanowicz study concludes, EPA misuses the DOE studies to derive CCS cost estimates. Commenter observes that these studies were intended to be used to derive preliminary estimates of feasibility and costs and never meant to determine actual costs to be used as a basis in a national rulemaking that will dictate the nation's future energy policy. Commenter states that the contention that based on these early projects the next-of-a-kind coal-based EGUs with partial carbon capture will somehow even approximate the LCOE data in Table 6 is not only arbitrary but meritless. Commenter closes, stating that   as they have pointed out earlier, the assumptions made to arrive at the Table 6 LCOE data, particularly for carbon capture costs, are not available and thus not reviewable for notice and comment in connection with this rulemaking. "It is not consonant with the purpose of a rule-making proceeding to promulgate rules on the basis of inadequate data, or on data that, critical degree is known only to the agency." Portland Cement 486 F.2d 375, 393. On this basis alone, commenter contends that the proposal in arbitrary and must be withdrawn.
Commenter 10395 states that  EPA compounds relies on three DOE funded demonstration projects when it details calculations and assumptions utilized to determine the levelized cost of electricity (LCOE) for what it describes as next-of-a-kind or "next commercial offering" for EGUs with carbon capture and lists these LCOEs in Table 6. However, the only projects EPA cites as a first-of-a-kind IGCC with carbon capture are the three identified DOE funded demonstrations. Without these projects, EPA lacks any basis to calculate and cite LCOE cost for "next" commercial offerings. Emissions from simple cycle plants are not trivial - Commenter 10119 states CO2 emissions from existing simple cycle plants totaled 22,679,318 short tons (nearly 20.6 million metric tons) in 2011 alone. Moreover, simple cycle emissions may well increase over the next eight years. EPA's own IPM model runs show that new simple cycle combustion turbine generation is expected to grow from 1,903 MW in 2016 to 5,052 MW by 2025, and  EPA does not quantify the potential emissions associated with this new generation, they may be expected to be significant given that capacity is anticipated to more than double.
 
Commenter 9600 states the contention that based on these early projects the next-of-a-kind coal-based EGUs with partial carbon capture will somehow even approximate the LCOE data in Table 6 is not only arbitrary but totally meritless. Even assuming that actual experimental cost data were not available, the DOE reports upon which EPA relies were not peer reviewed and underlying assumptions were not made available for comment in connection with this rulemaking. 
 
Commenter 9407 states the contention that based on these early projects the next-of-a-kind coal-based EGUs with partial carbon capture will somehow even approximate the LCOE data in Table 6 is arbitrary  and without merit. 
 
Commenter 9407 states the contention that based on these early projects the next-of-a-kind coal-based EGUs with partial carbon capture will somehow even approximate the LCOE data in Table 6 is arbitrary  and without merit.
Most of these comments are addressed in the preamble and in RTC 6, and the Cichanowicz appendix to UARG comments is addressed at response 3.3-16a above.  See section V.7. (costs decrease over time) and V.I.2. (reasonableness of NETL cost projections). Commenter 10046 suggests that DOE/NETL does not believe next plant costs will be NOAK.  The cost estimates for the final rule reflect the latest NETL cost study based on vendor quotes for the Shell Cansolv process  -  the process in current use at the Boundary Dam facility.  NETL believes these costs to be reliable as does EPA.  The costs also accord with prices quoted in the marketplace currently (see preamble section V.I.2.c) and cost estimates in other studies.  Id. section V.I.2.b. Commenters 10046 and 8971 claim that plants not yet built cannot provide enough information for next plants to be next-of-a-kind.  This is a dubious proposition, given that on-going experience provides useful information informing subsequent plants.  But there are operating plants  -  Boundary Dam is operational, the CCS portion of the Boundary Dam project came in at budget (the cost overruns commenters cite were for the SCPC), and the developer projects substantial reductions in cost for the next plant to be built.  

Commenter 10046 also maintains that the high end of the cost range for partial CCS is within the range of the $ MWh that EPA rejected as too expensive in rejecting full CCS as BSER.  This is misleading.  The relevant metric is the comparison of partial CCS with nuclear and other non-NGCC dispatchable baseload technologies.  Partial CCS, at the level which is BSER for the final standard of performance compares favorably with those costs, and is also considerably less than the projected $ MWh for full carbon capture (which the agency continues to reject on grounds of cost).
Do not base NOAK costs on partially constructed plants
Commenter 8925 states that basing "next of a kind" costs for the next CCS plant upon costs from these two partially constructed plants is inappropriate.  Commenter continues that the costs associated with CCS technology are highly uncertain, and EPA should use a sufficiently broad range of costs and broad range of timeframes for construction of the next CCS, to cover the wide band of uncertainty.
Commenter 9765 states that the OMB Report takes a particularly harsh look at the EPA's cost assessments. In particular, the OMB criticizes the EPA for relying too heavily on projects that are both inactive and extremely delayed or over budget. The report further states that "[o]f 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 ... [due to] cost overruns or uncertainty regarding the effectiveness and efficiency of the CCS technology." The EPA needs to consider fully the pervasiveness of cost overruns and failures before it attempts to mandate CCS technology through rulemaking. Commenter 9765 continues that Southern Company's Kemper Plant, for example, has experienced cost overruns of $2.32 billion as of April 2014.  Commenter 9765 adds that the Boundary Dam project in Canada likewise experienced cost overruns in recent months. SaskPower, owner of the Boundary Dam facility, announced last fall that the project had incurred $115 million in cost overruns. While this may seem small compared to the Kemper overruns, the Boundary Dam overruns are nearly 10% of the projects total cost, which will likely be passed on to rate payers.
See previous response.
Rule prohibits CO2 beneficial reuse
Commenter 10029 states that EPA briefly acknowledges the potential application of beneficial reuse technologies in the preamble to the proposed rule, noting the utilization of CO2 in the production of soda ash and food processing,29 but later in the preamble proposes that affected EGUs be permitted to use only geologic sequestration to store CO2. Commenter contends that in this way, the proposal impermissibly forecloses all beneficial reuses of CO2, which narrows the options available to affected EGUs, and prevents affected EGUs from offsetting the substantial compliance costs by selling captured CO2 for reuse.
See preamble Section V.H.7 (opportunities to further reduce compliance costs).
Cost offsets 
Commenter 9664 states that in regard to the revenue generated by the sale of captured CO2 for use in EOR, EPA properly considered this possibility. This approach is consistent with that taken previously by the Agency. For example, in its 2010 rulemaking on greenhouse gas emissions limits for motor vehicles, EPA factored the fuel savings expected to result from reduced rates of vehicle fuel consumption into the assessment of the rule's potential costs - as an offset to the costs of the control requirement. 
Commenter 10870 states looking to future, unproven and unrealized potential revenue to offset the exorbitant cost of CCS is not reliable. There is no demonstration that the speculative future revenues will ever materialize. 
The EPA found the costs of the standard of the performance to be reasonable without considering potential offsetting revenues from by-product sales.
CO2 price reality
Commenter 9780 states the EPA should revise its analysis to reflect more realistic prices for captured CO2 sold to EOR operators, explaining that EPA cites a recent NETL study as support for a price of $40/ton of CO2, but that this is an assumption DOE included in a model to estimate the oil recovered with advanced CO2-EOR, and it does not reflect current market price. Commenter continues the NETL study indicates captured CO2 price is $10.80/ton, and this price would presumably fall in the face of emissions standards that drove CCS and flooded the CO2 market.  
See previous response.
Market for CO2
Commenter 10786 states the NSPS's assessment of the market value of CO2 is factually inaccurate, explaining that the NSPS is premised in part on the assumption that there is presently a liquid market for CO2 for EOR operations that any entity capturing CO2 for compliance purposes under the rule will easily find a buyer, an EOR owner/operator willing to pay the prices cited in the Technical Support document. Commenter states this assumption is false for several reasons, including the market for CO2 is generally a liquid; no CO2 has yet been purchased that is subject to the described regulations and there is nothing in the rulemaking record to support EPA's conjectures about the value of the sources of CO2 that it hopes will be captured pursuant to the NSPS; the NSPS approach reverses the EOR-based value proposition. EOR operators (if any) may be expected to require commensurate compensation.
See preamble Section V.H.7.
EOR geographic constraints limit CCS sales
Commenters 9034, 0588, and 9780 addressed the geographic constraints of EOR on CCS sales. Commenter 9034 states neither transportation systems nor EOR opportunities are available nationwide, concluding that many coal-fired power plants will not have the option of selling their captured emissions to oil companies. Commenter 0588 adds that EPA's analysis does not account for regional differences in the availability of CO2-EOR, as EPA's cost estimates were based on coal fired power plants within 50 miles of geology suitable for CO2-EOR.37 (EPA's cost analysis, as summarized on Table 6. "Levelized Cost of Electricity for Fossil Fuel Electric Generating Technologies, Excluding Transmission Costs," (79 FR 1476), was "derived" from a study, "Cost and Performance of PC and IGCC Plants for Range of Carbon Dioxide Capture, DOE/NETL-2011/1498 (May 2011)," which only considered a hypothetical plant that transported CO2 50 miles via an already constructed pipeline. ) 
Commenter 9780 states CCS imposes an energy penalty in terms of the energy needed to compress, transport and inject the captured CO2 for storage; these efforts also entail additional costs. Commenter 10034 states EPA should evaluate whether the transportation of captured carbon poses unexpected costs for EGUs and how this factor affects the rule's economic feasibility.
Commenter 9731 states that NSPS should not be based on unrealistic commercial expectations. As proposed, the NSPS is premised on the assumption that CO2 will be marketable at any price. In fact, CO2 for EOR operations will be limited by demand, available pipeline infrastructure, and cost.
Commenter 10607 states the DOE and NETL costs exclude transportation costs of CO2, which could significantly increase the cost estimate for new sources implementing CCS technology. Section 111(a)(1) of the CAA requires that EPA account for the "costs of achieving such reductions." Since EPA is proposing that CCS is the BSER for coal-fired EGUs, EPA must account for the cost of transporting CO2. Commenter continues, stating in addition, the proposed regulation relies on the expected typical pipeline distance to be 50 miles to possible geologic sequestration sites. This distance underestimates the actual distances that may be necessary for the transmission of CO2. EPA is required to comprehensively evaluate the impact of all associated transportation costs via pipelines, including availability and acquisitions of right-of-way for new pipelines, capital and operating costs, and actual length of transmission pipelines. Other costs, including the performance of expensive seismic studies, must be accounted for prior to a regulated entity being able to store CO2 long term.
See preamble Section V.I.5 and other comment responses in chapter 6.
No class VI geologic sequestration well to date
Commenter (9683) states that because the EPA has yet to approve a single Class VI geologic sequestration well and apply the regulatory structure it has devised, no one knows the true cost of saline-based CCS.  
See preamble section V.N.
CCS and EOR: Nationwide geographic constraints
Commenter (10092) states it is critical to note that CCS may not be feasible on a nationwide basis and it may be more suitable in certain regions than others. 
Commenter 10618 states uncertainty persists regarding the availability of adequate sequestration sites within reach of existing units, the actual performance of available capture technologies, the actual performance of long term sequestration operations, and the long-term regulatory framework for liability. EPA touts the use of DOE funding for CCS projects. However, the DOE has repeatedly pulled funding from its FutureGen project. DOE funding alone has been insufficient to allow half of the award recipients to continue with planned projects and depends upon an appropriation system that is subject to the federal budgeting process.
Commenter 9600 states that it does not appear that the EPA has taken into account the costs CO2 pipelines, etc. Commenter 9003 states that EPA did not address the rise in consumer costs for electricity as a result of the CCS requirement. Costs associated with CCS could result in an increase in the wholesale price of electricity generated by coal plants by up to 80%. Commenter remarks that estimates of costs for carbon transport and sequestration may vary greatly by location. We do not believe the EPA has fully evaluated the costs for carbon transport and sequestration. Estimated long-term cost of pipeline transport and storage of captured CO 2has been estimated at $15/ton, with costs varying dependent upon source and site characteristics. While pipeline transportation is the most realistic technology available for moving captured carbon, estimates for average pipeline costs were approximately $4 million per mile in 2009. Truck transport cost, a likely mode for South Carolina utilities should it become necessary, may be approximately $6/metric tonne/100 km.
Commenter 8501 states it is unreasonable for EPA to conclude partial CCS imposes a reasonable cost on future projects by comparing the lifetime cost of generation of a coal-fired facility with partial CCS to the lifetime cost of other forms of electrical generation when geographic variables, type of load (base load versus intermittent load), and other factors significantly impact the feasibility of those forms of generation.
See preamble section V.I.5 and comment responses on issues of sequestration in chapter 6 of this RTC.
Identify geographic variation in CO2 storage costs in saline reservoirs
Commenter (10036) states costs based on storage in saline reservoirs should reflect the geographic variation in storage costs, adding EPA estimates the cost of transport, storage, and monitoring (TSM) of captured CO2 to be $10/tonne CO2 in the EPA Costing Analysis, and this is consistent with NETL's estimate of TSM costs for some regions, but not for others. For example, NETL estimates a $10/tonne CO2 value for TSM in the Midwest or Texas, but $15/tonne for North Dakota and $22/tonne for Montana. 
The EPA recognizes that the cost of CCS may vary depending upon the proposed location of the EGU based on geographic and other factors including locations of potential sequestration sites; however the EPA carefully reviewed the assumptions on which the transport and storage cost estimates are based and continues to find them reasonable. See section V.I.5 of the final rule preamble. The RIA presents an illustrative analysis using NETL estimates as demonstrative of the range of costs which, as the commenter points out, may vary by region. For transport, costs reflect pipeline capital costs, related capital expenditures, and O&M costs. Pipeline costs used in the NETL studies upon which the EPA analysis was based were comparable to costs quoted by industry experts. See Carbon Dioxide Transport and Storage Costs in NETL Studies (DOE/NETL-2013/1614), p. 16. Sequestration cost estimates reflect the cost of site screening and evaluation, the cost of injection wells, the cost of injection equipment, operation and maintenance costs, pore volume acquisition expense, and long term liability protection. These sequestration costs reflect the regulatory requirements of the Underground Injection Control Class VI program and GHGRP subpart RR for geologic sequestration of CO2 in deep saline formations. The transport and storage costs provide a conservative estimate of storage costs and are consistent with cases modeled in the NETL report. The EPA believes that the use of costs and scenarios presented in the studies referenced are representative for purposes of the cost analysis. The NETL cost estimates upon which the EPA's costs are based draw directly from the UIC Class VI economic impact analysis. That analysis is based on estimated characteristics for a representative group of projects over a 50-year period of analysis, as well as industry averages for several cost components and sub-components. Additionally, there are alternative compliance paths available to meet the promulgated standard of performance which do not involve sequestration.  
CCS byproduct revenues
Commenter 10870 states the EPA asserts that it may reasonably consider the potential to generate revenue from the by-products of identified control technology. 79 Fed. Reg. 1464/3 and that this conclusion - which has not been tested in court - is an important factor supporting EPA's determination that the costs of CCS are reasonable for the coal unit subcategory. Commenter continues that looking to future, unproven and unrealized potential revenue to offset the exorbitant cost of CCS is not reliable, and there is no demonstration that the speculative future revenues will ever materialize.
Commenter 9195 states EPA's proposed rule states that the levelized cost of electricity (LCOE) for partial CCS is "comparable to other non-NGCC generation, after accounting for revenue from the sale of CO2 for EOR." EPA states that "[w]hen 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 reasonable." Commenter states that it is apparent that not everyone shares this assessment, offering, for example, that while the Energy Information Administration (EIA) considers LCOE to be "a convenient summary measure of the overall competitiveness of different generating technologies" it notes that "actual plant investment decisions are affected by the specific technological and regional characteristics of a project, which involve numerous other considerations." EIA further stated that "[s]ince projected utilization rates, the existing resource mix, and capacity values can all vary dramatically across regions where new generation capacity may be needed, the direct comparison of the levelized cost of electricity across technologies is often problematic and can be misleading as a method to assess the economic competitiveness of various generation alternatives." Commenter requests any records demonstrating that EPA considered and/or rejected EIA's January 2013 assessment of LCOE. Commenter asks that if EPA does not believe that use of LCOE in CAA rulemaking can be "problematic" and/or "misleading", then please provide the committee with the technical basis for this assessment and your accompanying economic rationale. Commenter states EPA claims to have considered the costs of various BSER alternatives and to have rejected several lower cost options on the basis that they would not result in "significant reductions" in GHG emissions and, in turn, commenter asks what EPA considers to be an acceptable cost-per-ton of CO2 removed from EGUs.
Commenter 9765-7130, 7131, 7132, 7133, 8134, 7135, 7136  states that the District of Columbia Circuit requires that a system of emission reduction "serve the interests of pollution control without becoming exorbitantly costly in an economic or environmental way" to be considered adequately demonstrated under the Act. Essex, 486 F.2d at 433. The EPA concludes that the cost of partial CCS is reasonable to impose on all new coal-fired EGU's. The assumptions imbedded in the EPA's cost analysis, however, lack credibility and do not accurately reflect the exorbitant cost of requiring CCS on all new facilities.  Commenter states that one of the inadequacies in the EPA's Proposed Rule is the inclusion of enhanced oil recovery (EOR) revenues as a basis for reducing the estimated levelized cost of electricity (LCOE) for coal-fired power plants. 79 Fed. Reg. at 1475-76. The EPA claims that it is reasonable to include revenue-generating opportunities of its CCS technology mandate in the cost of doing business, thereby artificially lowering the LCOE for coal-fired plants to make it appear that coal is still a realistic option for energy production under the Proposed Rule. At the same time, the EPA acknowledges that EOR may only be available at some power plants. Commenter states that the inclusion of EOR revenues in its consideration of cost of CCS is inappropriate for four reasons. First, the EPA states that a going rate for one ton of CO2 is between $20 and $40 without identifying the source of this figure. Based on other figures that the EPA uses to justify this rule and the fact that no full-scale commercial carbon capture projects exist, we can only assume that the EPA derived these figures from the sale of CO2 from small carbon capture pilot projects. Prices achieved through sale from pilot projects may have no bearing on the prices derived from capture at large-scale commercial power plants, especially if the EPA does not account for economic factors such as the increase in supply of CO2, the costs associated with such large-scale capture, or the cost associated with distribution of CO2 to potential buyers. 2) Second, two unreasonable assumptions are made in its Proposed Rule: 1) that the EPA can artificially create a market for CO2 in regions of the country where no oil production exists, and 2) that it can expand the already present EOR business in other areas of the United States simply by creating a ready supply of CO2, Basic economics instructs that for a successful market exchange to occur, both supply and demand need to exist. The EPA did not demonstrate adequate demand for the high amounts of captured CO2 that this rule would bring to market, and therefore did not justify its inclusion of EOR revenues as a cost reduction mechanism. Third, the EPA does not include the true costs of carbon capture technology. The EPA primarily uses National Energy Technology Laboratory (National Laboratory) LCOE figures to estimate the future costs of energy production. See, e.g. 79 Fed. Reg. at 1476. The Energy Information Administration (EIA), a group who creates independent and impartial energy studies used to support policy decisions, is also cited throughout the Proposed Rule but is inexplicably left out of the cost analysis for fossil fuel fired power plants. Id. The EIA figures are substantially higher than National Laboratory cost analyses. The inclusion of these figures into the cost analysis would undercut EPA's argument that the costs of this rule are reasonable, as well as negate the benefits derived from inclusion of EOR revenue. Fourth, the EPA includes the speculated revenue from EOR in its cost projections, yet it does not include all reasonable costs associated with EOR. In an interagency comment letter from August 2013, the EPA acknowledges that the cost estimates it used in its Proposed Rule exclude costs of "land acquisition and right-of-way, permits and licensing, royalty allowances, economic development, project development costs, allowance for funds-used-during construction, legal fees, Owner's engineering, preproduction costs, furnishings, Owner's contingency, etc." The cost estimates also exclude site-specific considerations, such as seismic activity, local regulations, and accessibility. It is obvious that these costs are the exact types of outlays a utility would consider before constructing a new plant, especially one that incorporates EOR. Thus, the EPA should include these types of costs in its analysis in order to reach a meaningful conclusion. Until the EPA addresses the four issues above, the EPA should not include EOR revenues in its cost assessments to lower the estimated cost of carbon capture.
Commenter 9765 continues that they  disagree with the assessment that each coal-fired facility built in the future will be able to implement partial CCS in a manner that is both environmentally sound and not cost prohibitive to rate payers. They state that in this respect, the EPA did not consider fully the breadth and scope of the factors Congress provided for making a BSER determination. Commenter remarks that while the EPA gives ranges in its LCOE assessment for supercritical pulverized coal (SCPC) and integrated gasification combined cycle (IOCC) facilities, it is not possible for the EPA to have considered all costs associated with the implementation of partial CCS. The reason such a cost analysis is not possible is that the costs associated with each facility employing CCS technology require consideration of site-specific information. For instance, CCS is not one solitary defined piece of equipment that an operator can install on a facility. Rather, CCS is, at a minimum, a three-step process. Thus, an operator must combine three or more types of technology to make one CCS system work. Commenter 9765 concludes that because of this complexity, the EPA must first conduct a cost analysis on all available capture methods, including pre-combustion, post-combustion, and oxycombustion techniques. Next, the EPA must address costs associated with the compression and transportation of CO2, This analysis will vary significantly with each location and requires the EPA to consider many factors, including "availability and acquisition of rights-of-way for new pipelines, capital costs, operating costs, length and diameter of pipeline, terrain, flow rate of CO2, and the number of sources utilizing the pipeline." After consideration of these variables, the EPA must then assess costs associated with storage or sequestration. Again, the site-specific characteristics, such as the distance of a plant from an adequate sequestration location or EOR project, will have a significant bearing on cost estimates. Additionally, closure and post-closure costs, monitoring costs, plug and abandon costs, and ongoing financial responsibility must be assessed if sequestration is chosen, which will likely vary with the size, depth, and type of formation selected. Commenter further concludes that given the multitude of site-specific factors involved in planning for CCS technology, and the extremely site-specific nature of each facility, it is inappropriate to claim EPA can conduct an adequate cost analysis of imposing CCS technology on all new coal-fired power plants across the country. This rule is not as simple as proposing the addition of a safety switch or new air filter; it requires innumerable nuanced calculations that the EPA cannot possibly calculate for every facility absent site-specific facts. The EPA cannot claim to create a national rule meant to address any situation in which a coal-fired power plant will be built, while ignoring nearly every variable that a utility company would consider when choosing to build.
The EPA is not considering EOR revenues in its determination that costs of the standard of performance are reasonable and not exorbitant.  Regarding site-specific costs, the EPA made reasonable, representative cost estimates, and specifically included costs for all of the items related to local property rights (rights of way, land acquisition, pore acquisition rights, etc.) mentioned by commenters.  See preamble section V.I.5.  The EPA notes that the costs related to sequestration were developed for the Class VI rule, a rule that is already in effect and was not challenged in court.  Moreover, there are compliance alternatives available under the final rule which do not raise these site-specific concerns, since they do not involve sequestration.
Carbon sequestration costs and risks
Commenter 9765 states the EPA must provide an analysis of the technical, economic, and legal issues related to geologic sequestration if sequestration is to be included in the IPM model. Based on Wyoming's experience as a leader in addressing collateral issues associated with carbon sequestration, the framework that is required to ensure the long-term viability of carbon storage must be determined at the state and local level in the absence of a federal, unified framework. Such local efforts involve notable resource investments in time and personnel, and can conceivably have the same or larger impact on the overall viability of any project involving carbon storage. The EPA, however, did not evaluate these investments and costs prior to issuance of the Proposed Rule.  Further, the EPA did not provide a detailed analysis of the accessibility to CO2 pipeline infrastructure for EOR. 
Commenter 9765 continues the complexity of the issue shows that the EPA's predictions are extremely speculative, especially when forecasting the long-range effects of this technology mandate. As described in detail in a report to the Wyoming State Legislature, considerable financial risks and costs persist throughout the life of a CO2 storage site, beginning with siting, permitting, and construction, and continuing on through operation, post-closure, and long-term stewardship of the facility. Post-closure would require a facility to actively monitor its site to make sure the site is safe and secure, the CO2 plume has stabilized, and the site could be safely abandoned. Long-term stewardship would require monitoring and continued financial risk for a lengthy or possibly indefinite period. Commenter adds that EPA's Proposed Rule does not address the management of displaced fluids from carbon storage. Injected CO2 will displace fluids from the storage area. An operator must transport those fluids to avoid disruption of confining spaces and destruction of the integrity of the storage system. Fluid management would likely include water treatment and management at the surface, which would also be costly. These costs of monitoring and water treatment would pale in comparison to the financial risks associated with induced seismicity, which could lead to subsidence or uplift, causing property or infrastructure damage, as well as possible impacts to water quality. In addition, plume leakage or migration into recoverable mineral zones could lead to mineral rights infringement and legal costs associated with settling those disputes. On top of all this uncertainty, the EPA fails to address the differences in regulation of oil and gas between different states. 
Commenter 9765 continues  that they consider the Proposed Rule inadequate in addressing the costs and the potential financial and legal risks associated with carbon capture and storage, and urges the EPA to conduct a full accounting and consideration of these risks and costs before carbon storage is a required control system in this or any other rule. 
The EPA has in fact thoroughly considered the technical, economic and legal issues related to CO2 transportation and geologic sequestration. For transport, costs reflect pipeline capital costs, related capital expenditures, and O&M costs. Sequestration cost estimates reflect the cost of site screening and evaluation, the cost of injection wells, the cost of injection equipment, operation and maintenance costs, pore volume acquisition expense, and long term liability protection. These sequestration costs reflect the regulatory requirements of the Underground Injection Control Class VI program and GHGRP subpart RR for geologic sequestration of CO2 in deep saline formations.

The United States has a robust pipeline network. The CO2 pipeline network in the United States has almost doubled in the past ten years in order to meet growing demands for CO2 for EOR. CO2 transport companies have recently proposed initiatives to expand the CO2 pipeline network. Several hundred miles of dedicated CO2 pipeline are under construction, planned, or proposed, including projects in Colorado, Louisiana, Montana, New Mexico, Texas, and Wyoming. Furthermore, in the final rule the EPA has provided multiple compliance pathways for this NSPS, including geologic sequestration in various storage formations and through EOR, as well as storage alternatives that entities may submit to the EPA for case-by-case consideration. Potential sequestration sites are located throughout the U.S., including deep saline formations and other non-EOR formations. Additionally, for the few states that do not have geologic conditions suitable for GS, or may not be located in proximity to these areas, in some cases, demand in those states can be served by coal-fired power plants located in areas suitable for GS and the electricity they generate can be delivered through transmission lines, and in other cases, coal-fired power plants are unlikely to be built in those areas for other reasons, such as the lack of available coal or state law restrictions against coal-fired power plants.

The EPA notes that issues of individual property rights will involve site-specific resolution if and when they arise in particular proceedings. These issues have not proved impediments to the Class VI projects pursuing GS, as illustrated by the cases of Archer Daniels Midland and FutureGen. The EPA notes that the cost estimates for this rule include costs for acquiring both surface land and sub-surface property rights (pore acquisition).

With respect to liability, in general, the risks associated with geologic sequestration of CO2 are expected to be highest during the operational phase of the project. The risks are then expected to decrease over time. The 2010 Report of the Interagency Task Force on Carbon Capture and Storage discusses how scientific research has concluded that there is substantial evidence that CO2 will remain in place for extended periods if the injection site is chosen properly, injection operations are conducted according to regulations, the site is monitored adequately, and post-injection and closure operations are conducted appropriately. The EPA's existing regulations for geologic sequestration provide a framework to assure the safety and efficacy of GS, which can help assure lenders considering financing sequestration facilities. Furthermore, first mover projects are in operation and have been able to obtain needed financing. See also section 6.3 of this response to comments document. 
Cost should include NG infrastructure improvements to support increased consumption
Commenter 10039 states EPA's reliance on DOE/NETL "Cost and Performance" reports underestimates sequestration costs significantly and skews the reports to favor NGCC as a result. Commenter adds the EPA when utilizing DOE data, did not include costs for NG infrastructure improvements to support the increase in NG consumption that will accompany continued expansion of NGCC units as a source of base load power generation. Not considering these costs results in NGCC costs being biased low. Using biased data skews US EPA's analysis in favor of NGCC making the use of those cost estimates arbitrary and capricious.
Commenter 9597 states the costs and permitting associated with upgrades to the natural gas infrastructure can be quite substantial and require years, if not decades to complete. In particular, as lower Michigan is a peninsula, supply routes are severely restricted by the presence of the Great Lakes. EPA must provide robust cost analyses evaluating the necessary upgrades to the national infrastructure to comply with this proposal.
Commenter 7977 states the Interstate Natural Gas Association estimates that, through 2035, the United States and Canada will need 600 miles per year of new lateral lines to and from natural gas-fired power plants, processing facilities, and storage fields, 1,400 miles per year of new gas transmission mainline, and 16,500 miles per year of new gathering lines in order to meet infrastructure needs. Collectively, the natural gas, NGL, and oil midstream sector will require total capital expenditures of $10 billion per year or a total of $251.1 billion (Real 2010$) through 2035.
Commenter 10393 states that EPA's economic analysis incorrectly predicts that building only new natural gas-fired utilities would make no difference to society because of the current abundance of this resource and its current cost relative to coal. The proposal does not acknowledge that significant amounts of natural gas infrastructure need to be built to move and store the natural gas in close proximity to each power plant.
Commenter 9600 states that  new generating units may need to be located where needed electric transmission capacity would allow the source's effective contribution to grid reliability but where no or limited natural gas supply capabilities or carbon sequestration infrastructure exist. A source's definition may well include local coal utilization as a means of contributing to the local tax base, economic development, or employment opportunities. In any of these and other circumstances where source definition includes the need to locate the source to fulfill a local need or take advantage of a local resource and that definition include coal utilization the imposition of the proposed NSPS allowing only carbon capture and sequestration where resources are unavailable to do so would be unlawful as requiring source redefinition. Commenter concludes that for these reasons coupled with this proposal's requirements that prohibit source locations where CCS infrastructure is unavailable thus new coal-fired EGUs is prohibited, the proposal is unlawful.
Commenter 10024 states that the proposal does not acknowledge that significant amounts of natural gas infrastructure need to be built to move and store the natural gas in close proximity to each power plant. Commenter believes the Agency ignored these localized cost factors entirely when attempting to levelize the cost of electricity in its analysis. 
EPA disagrees.  EPA's proposal and final rule acknowledges the need to build infrastructure to address increases in consumption of natural gas.  The EPA modeling presented in the RIA in the proposal and this final rule uses the IPM model that includes both planned infrastructure, contains a detailed representation of the natural gas supply and pipeline system, and models the construction new pipeline capacity where it is needed to supply increases in demand.  (See RIA at p. 4-5 and  http://epa.gov/powersectormodeling.)
3.3.1 Costs of a New Coal-Fired Unit With Partial CCS vs. One Without CCS
CCS too costly
Multiple comments were received stating CCS is too costly. Commenter (10098) states that EPA's conclusion that the cost of partial CCS is "reasonable" is specious, arbitrary and capricious, and violates the CAA given that the Agency's position in its own GHG Guidance and the history of permitting agencies finding CCS to be prohibitively expensive (and EPA concurring with or declining to dispute those conclusions). Commenter (9034) states CCS costs surpass the threshold of "exorbitant" and "excessive", stating that to produce the same amount of electricity for consumers, a CCS-equipped plant would have to be significantly larger than a plant without CCS given higher cost of CCS. Commenter adds that a CCS-equipped unit would likely incur significant costs storing the CO2 and building and operating a pipeline to transport the CO2 to the sequestration location (or ultimate use destination), assuming property rights and regulatory approvals can be obtained (which is uncertain) and assuming sequestration facilities, natural or man-made, are available. Commenter (9034) states EPA's proposal for coal-fired power plants is cost prohibitive compared to the costs of electric generation by other energy sources, explaining that the Energy Information Administration estimates that the cost to build a new IGCC coal plant with CCS translates to $6,599 per kilowatt ("KW"). Commenter add this is more than six times the price per KW of a new NGCC plant; triple the price per KW of a new onshore wind farm;  double the cost per KW of new hydropower;  and more than $1,000 per KW more expensive than solar or nuclear. Commenter (9683) states a typical seasonal market price in PJM, the country's largest power market, could be expected to range within the $50-60/MWh level (and acknowledges that other areas of the country would differ), and the cost of adding CCS to a coal-fired generating unit may be in the $30-40/MWh range, meaning the cost of CCS alone may be some 50-80% of the market price for power, which is on top of the amount that must be recovered to make economic the new unit even without CCS. Commenter states that special circumstances (availability of subsidies, cost recovery, revenues from the sale of CO2 and other byproducts, and benefits to a host State such as revenue from increased oil production from EOR or use of coal that otherwise would not be mined) may provide benefits that cause a project overall to serve State interests and prompt developers to pursue CCS but such circumstances depend heavily on geology known today to exist only in a few areas. The commenter quotes cost estimates by Deputy Assistant Secretary of Energy for Clean Coal Julio Friedmann and former Assistant Secretary McConnell.

Commenter (9683) provides several examples where facilities currently attempting to incorporate CCS technology have encountered problems because of cost.
Commenter 10097 states that the rule would set national electricity energy policy for years to come and force coal-based generation costs higher than other new base-load generating options.
Commenter 9507 states the proposed rule gave a cursory nod to the economic and energy aspects of the proposed NSPS by noting that the costs of CCS are expensive. However, the proposal ignores the sheer magnitude of the energy penalty and the attending economic penalty associated with CCS. The proposal provides no quantification of current or projected energy impacts. Given that every major piece of legislation since the Energy Crisis of the 1970s has sought to conserve fuel resources, it is clear that EPA needs to address this issue in finer detail before imposing a CCS mandate.
Commenter 9594 states U.S. consumers of energy benefit most from an all-of-the-above energy marketplace. Diversity of energy supply is critical to providing reasonably priced energy and for ensuring steady and reliable streams of energy to power our factories and heat our homes. Energy is currently an advantage for many U.S. industries, including forging, in large part because abundant and diverse supplies of energy resources are helping to keep energy costs reasonable and supply reliable. However, EPA's proposal would reduce the energy options available to everyone, resulting in increased volatility and cost and threatening reliability. 
Commenter 9777 states in 2013, the U.S. Energy Information Administration (EIA) updated its capital cost estimates (from 2010) for utility scale generating plants. EIA currently estimates the capital cost of a single advanced PC unit with CCS to be $5,227/kW and a single IGCC unit with CCS to be $6,599. The 26% higher cost of IGCC with CCS over a PC unit with CCS may be underestimated when compared to the owner's projections of cost on projects under development. EIA's costs projections are conservative compared to those of other administration officials.  
Commenter 9777 states Potomac Economics Ltd, in a market report on the Electric Reliability Council of Texas (ERCOT), reported the actual average real -time electricity price in $/MWh from 2009 to 2012 as follows: 2009 - $34.03; 2010 - $39.40; 2011 - $53.23 reflecting increases in natural gas prices; 2012 - $28.33. Given these average market prices, such CCS-equipped supercritical units would not be able to acquire financing and might only be dispatched within ERCOT on very infrequent, high peak-load occasions.  Commenter continues that in a competitive market like Texas, unit efficiency is a key factor in determining the order in which generating units are dispatched to operate. Thus, minimizing auxiliary load (power used within the unit and not available for sale) is a financially incented requirement. In the 2011 Cost and Performance Baseline for Fossil Energy Plants DOE/NETL report that lignite supercritical 550 MW unit modeling runs show that the installation of CCS on a unit increases the auxiliary load from 34.6 MW to 133.8 MW, a 287% increase.
Commenter 9777 also remarks that the 2012 report, Current and Future Technologies for Power Generation with Post Combustion Carbon Capture, Final Report, projected auxiliary loads to increase from 30.4 MW to as much as 112.8 MW, a 271% increase. This increase in auxiliary load appears to be independent of fuel type since the report modeling is based on a unit firing Illinois No. 6 - a bituminous coal. In both DOE/NETL reports, the units modeled with CCS are designed at significantly higher gross MW ratings in order to provide approximately 550 MW net. This sizing up of the boiler, turbine and generator result in higher consumption rates for coal, increased emissions that will require enlarged pollution control systems, increased water consumption, greater auxiliary loads, and increased capital and operating costs all due to the addition of CCS systems. If the economics of CCS presented in the DOE/NETL work are reasonable and relatively accurate, new coal units with CCS would not be competitive in the Texas market unless gas prices increase many times over the current prices. Since such cost increases are not forecast at this time, the likelihood of building a coal unit in Texas is effectively zero. The removal of coal-fueled generation as a viable alternative for future generation will increase dependence on natural gas in Texas and reduce the fuel flexibility of the Texas fleet.
Commenter 9777 continues, stating EPA's Regulatory Impact Analysis does not to accurately assess costs Luminant finds EPA's assessment of the costs and benefits of this regulation incomplete and disingenuous. Certainly, the cost of CCS is not negligible to either the electricity generator or the electricity customers who will ultimately bear the brunt of a regulation that does not consider the long term effects of expensive control requirements that yield negligible reductions while reducing the electricity diversity that helps buffer volatile prices and ensure reliability. Commenter states that if EPA persists in pursuing a strategy that effectively eliminates any new coal construction, it must complete a robust economic evaluation of how the demise of coal-power generation would affect the economy on a short- and long-term basis.
Commenter 8024 states that EPA's Regulatory Impact Analysis for the proposed rule shows that CCS raises the cost of electricity from a new supercritical unit by 36% to 81%, depending on whether it uses partial or full CCS. Costs for plants that have access to EOR markets for CO2 sales are 17% to 42% higher than EPA's base case. We strongly disagree with EPA's position that such cost increases are reasonable under applicable case law precedent such as Portland Cement.
Commenter 9765 states that the proposed Mongstad plant in Norway is another example of considerable cost overruns. These cost overruns eventually led the Norwegian government to cancel the project. Not only do all three of these examples demonstrate the costly nature of CCS technology, but they also show just how difficult it can be to forecast the costs associated with this unproven technology.
Commenter 10046 states  EPA's own economic modeling shows that there will be no new coal plants with partial CCS built that will be subject to this proposal. Consequently, EPA has no evidence that these costs can be easily passed along to the consumer, or that they can plausibly be absorbed without affecting industry structure or profitability.
Commenter 10022 states the cost of partial CCS will be exorbitant and cannot be supported by the limited population in Alaska.
Commenter10089 states in May 2014, the U.S. Global Change Research Program released its National Climate Assessment report which discussed, inter alia, the potential for CCS to assist in reducing the electricity sector's impact on climate change. Indeed, while acknowledging the potential of CCS to capture 90% of carbon emissions from coal and natural gas combustion processes, the report cautioned that CCS remains a highly cost-intensive technology that has not been widely deployed citing ref. "Although the potential opportunities are large, many uncertainties remain, including cost, demonstration at scale, environmental impacts, and what constitutes a safe, long-term geologic repository for sequestering carbon dioxide." OPC cautions that mandating the integration of a new, cost-prohibitive technology without evidence of the technology's successful performance in the marketplace could have a deleterious impact on ratepayers. Commenter acknowledges, though, that the current exorbitant cost of CCS could decrease in coming years as more utilities install CCS at their power plants. As with any new technology, once a few energy-market participants successfully utilize CCS, such early adopters may likely incite an upward trend of mass adoption of the technology by electric generators. This prospective increase in demand for CCS could lead to increases in the production of the technology, which would reduce costs.
Commenter 10135 states the EPA's proposed GHG emissions limits will impose substantial costs on and will inhibit the future development of new coal generation in the PJM region, explaining that the PAPUC opposes the EPA's proposed BSER standard and associated emissions levels for new coal-fired and IGCC units insofar as these standards are based on experimental and unproven technology.
Many of these comments are out of context, referring to EIA and DOE Secretary Julio Friedman statements regarding full, not partial, CCS. (Commenters 9683 and 9777, for example.)  The commenters also cite $ MWh figures that are considerably higher than the EPA projects for the final standard of performance.  See preamble section V.H.5.a. The EPA notes further that the final standard is less stringent than the proposed standard, in part in response to comments regarding cost.  

The Cost figures cited by commenter 8024 are not correct based on the requirements of the final rule and the cost and performance data in NETL 2015. The levelized cost of a coal-fired power plant with CCS is 5-21% more than for a coal unit without, depending on whether or not the CUA is included for the non-compliant unit. The LCOE for a coal-fired power plant meeting the standard by co-firing natural gas is 12% more expensive than for a non-compliant unit when not considering the CUA and lower than for a non-compliant unit when the CUA is included. See RIA Figure 4-3. The commenter is correct that revenue from EOR would partially offset the costs of CCS.

Many of the cost and performance values cited (e.g., "the installation of CCS on a unit increases the auxiliary load from 34.6 MW to 133.8 MW, a 287% increase") are for cases where "full CCS" (i.e., capture and storage of > 90% CO2) is assumed. The EPA does not find that full CCS is a component of the BSER for new fossil fuel-fired steam generating EGUs.

The referenced Mongstad Project was a full-scale capture project which was intended to capture exhaust gases from a residue catalytic cracker and a combined heat and power natural gas-fired power plant. The EPA does not find that full CCS is a component of the BSER for new fossil fuel-fired steam generating EGUs and the EPA does not find CCS to be a component of the BSER for new base load stationary combustion turbines.
CCS costing is speculative
Commenter 10023 states that EPA's discussion of the costs of CCS is so speculative as to render arbitrary its conclusions about the cost differential between new Subpart Da units equipped with CCS and other generation sources. Commenter adds that EPA cannot rely on the potential resale of captured CO2 for use in EOR to reduce the expected costs of its CCS mandate.
Commenter 10098 states no effort was made to assess the costs associated with the CCS facilities it relies upon to establish that CCS is BSER, nor does it address the significant cost overruns associated with CCS technology, and even under this cursory and insufficient analysis, EPA concludes that the costs of requiring CCS are likely to exceed the benefits. 
Commenter 10097 states the proposed BSER requiring partial carbon capture has not be adequately demonstrated because the system of emission reduction is excessively costly. The proposal references three Department of Energy (DOE) studies to access cost and performance of coal and natural gas EGUs. The most recent one addresses carbon capture. EPA relies exclusively on these studies to predict the levelized cost of electricity (LCOE) for SCPC and IGCC EGUs, including LCOE costs for no carbon capture, partial carbon capture and full carbon capture alternatives. Table 6 in the proposal summarizes the LCOE costs based on these studies. Id. EPA relies on these LCOE cost data to conclude that cost of partial carbon capture as BSER is reasonable. Commenter states that the studies themselves are too unreliable and speculative to be used to reasonably determine the state of technology and associated costs of carbon capture.  Commenter 10097 continues that EPA cannot reasonably rely on Table 6 LCOE data that are based the theory that as technology matures with the construction of successive plants, the cost decreases. Further, commenter 10097 states that the LCOE data used to justify that partial carbon capture technology in the "next commercial offering" will be reasonably priced do not comport with actual cost data associated with existing projects including those that are receiving funding under DOE's clean coal demonstration program.
Commenter 9407 states there are fundamental problems with EPA's reliance on these studies and the resultant calculated LCOE to determine BSER is reasonably costly in the context of rational rulemaking. The proposal and information contained in the rulemaking docket provide no rationale explaining how EPA arrives at these specific Table 6 LCOE predictions.
Commenter 9423 remarks that EPA states that the cost of building and operating a coal-fired power plant that meets the proposed BSER is reasonable, because its cost of producing electricity is comparable to other power generation processes, including nuclear power plants. Commenter contends EPA's rationale for its position on reasonableness is not a substitute for a true and complete analysis of the cost of CCS.
 Commenter 10097 states the assumptions made to arrive at the Table 6 LCOE data, particularly for carbon capture costs, are not available and thus not reviewable for notice and comment in connection with this rulemaking.
The cost estimates for LCOE are documented with great transparency  -  indeed, virtually line item by line item  -  in the various NETL studies.  The EPA is relying on the most recent of these studies, which bases cost estimates on vendor quotes for the process currently in use at the Boundary Dam facility  -  the Shell Cansolv process.  Among other indicia of this study's reliability is that AEP represented the cost of the Turk SCPC facility as $2,885/kW (comment p. 76). The DOE/NETL estimates for such a facility is $2,842/kW (NETL, 2015  -  for a plant using bituminous coal).  This close agreement is a good indication of the study's reliability.  In addition, see preamble section V.I.2 indicating agreement of NETL estimates and those of other expert techno-economic models, as well as current marketplace vendor quotes.
Partial CCS as BSER for NGCC is less costly than for coal plants
Commenter 8501 states that EPA's justification for rejecting CCS as BSER for NGCC plants is not supported by facts or the record. Commenter adds that EPA does not explore whether the total cost of utilizing partial CCS on NGCC plants could be less costly than requiring it for coal plants. Commenter posits that NGCC exhaust requires significantly less pre-cleaning prior to CO2 capture, which could result in a significant difference in the overall cost effectiveness for the two types of power plants.
See preamble Section IX.C.4.
Steam demand
Commenter 8966 states that many types of CCS systems can only be installed alongside specialized plants with altered process flows designed to integrate with CCS equipment. For instance, many post-combustion CCS systems, such as chilled ammonia-based capture technology, require large amounts of steam to sufficiently process and activate the reagent necessary to execute the capture of carbon dioxide from the flue gas. Commenter states that to meet these steam demands, it is necessary to channel steam away from the EGU's boiler chamber or turbine system. However, such a diversion significantly alters the EGU's Rankine cycle, thus requiring reworking of conventional steam paths and recalibration of the turbine-generator. In addition, some types of post-combustion CCS systems require a level of flue gas desulfurization and purification that exceed even the most advanced catalytic reduction retrofits, necessitating design of a more complex combustion process. These custom-designed facilities are significantly more expensive than conventional coal-fired plant designs. Despite these increased costs, there will still be some loss of steam in the channeling process, compromising the efficiency of the EGU. Since the amount of carbon produced from conventional coal plants is far greater than natural gas-fired EGUs, the efficiency losses are significantly higher for coal-fired plants implementing CCS. Therefore, there is a multitude of costs distinctly applicable to coal-fired power plants in addition to the costs of the CCS system itself.
 The final standard of performance could be met by a new SCPC EGU utilizing 16% CCS. The EPA has evaluated the effect on energy demand in preamble section V.O and determined that 16% partial CCS would increases the parasitic demand on the new unit from 5.2% to 6.3%. The use of partial rather than full CCS minimizes the parasitic energy demand on the new unit.
Flawed cost comparison of CCS to nuclear
Commenter 10100 states that EPA's cost reasonableness analysis of CCS,  improperly compared the costs of constructing coal-fired EGUs employing partial CCS with the costs of constructing nuclear or biomass plants. See 79 Fed. Reg. at 1477. Although EPA may consider compliance costs on a national level when determining the BSER, this does not authorize comparisons with tangentially related source categories or subcategories. Such consideration of costs outside the subcategory subject to the proposed standard is arbitrary and an improper extension of EPA's authority. EPA is required to compare the cost of the most recently built, most efficient coal plants with the cost of constructing those same plants with CCS. 

Commenter 10023 states that EPA compares the benefits of using NGCC to that of using a traditional pulverized coal unit. It is not clear, however, why EPA is comparing NGCC to conventional coal units. Commenter contends that the proper analysis should be of the estimated costs and benefits of constructing a conventional coal unit with a coal-fired unit that would meet the proposed standards.
See preamble Section III.G.1.
EPA did not adequately consider health and environmental impacts or energy requirements
Commenter 9427 states CAA Section 111 specifically requires that "nonair quality health and environmental impacts and energy requirements" be taken into account in determining BSER and a proposed standard of performance. They state that EPA did not adequately consider or analyze the health and environmental impacts or energy requirements of "partial CCS" in its proposal, stating that the proposal only addresses nationwide impacts, in a very abbreviated and vague manner or by the use of general statements such as that there would be a "decreased electricity output (energy penalty)" resulting from CCS (79 FR 1472). EPA's proposal mentions, but does not consider, adverse CCS effects such as reported by the U.S. Department of Energy, National Energy Technology Laboratory (DOE/NETL). EPA's proposal refers to a May 27, 2011 edition of the report (79 Fed. Reg. at 1471, footnote 190, but only in the context of "technical feasibility" of carbon capture, not for energy or environmental impact information)  indicating significant energy, efficiency, water use, air emissions, and cost impacts that could result from partial CCS.  For evaluation, the DOE/NETL report uses a 550 net MW unit operating at an 85% capacity factor. For a pulverized coal supercritical boiler, Case 0 provides data for a unit without CCS, while Cases 1A and 1B provide data for partial CCS in the range that the proposed Subpart Da standard would require. 

Commenter 9777 states even if it were economically viable, which it is not, the CCS process is a water intensive process and sufficient quantities of additional water do not exist in Texas to provide either the necessary increased withdrawals or consumption.
 
Commenter 10880 states the EPA did not adequately consider the environmental consequences of the proposed rule. The proposed rule will result in increased natural gas production, and with that, increased exploration, development, production and transportation of natural gas to supply the power sector. The increased land use and other environmental impacts of increased natural gas drilling, natural gas and CO2 pipeline construction and sequestration storage and injection sites were not adequately considered. The IPCC estimates methane as 34 times stronger a heat trapping gas than CO2. The EPA did not adequately consider the methane emissions, increased impact to groundwater, and increased water use from added natural gas well fields.
 
Commenter 9765 states the energy penalty associated with CCS technology has an additional consequence that the EPA fails to acknowledge; an increase in the rate at which America literally burns through its valuable natural resources. In order to make up for the parasitic reduction in energy due to CCS, facilities will be required to bum more coal. Based on current efficiencies, facilities will need an additional 25% to 33% more coal to continue producing the same amount of energy as they would without CCS. Id. Through the burning of more coal, each facility has the potential to produce higher quantities of pollutants that facilities must then manage, including sulfur oxides (SO2), nitrous oxides (NOx), carbon monoxide (CO), particulate matter (PM), coal ash, and mercury (Hg). Whether facilities can manage the increase in other pollution streams is another question the EPA does not answer. Commenter closes that because the EPA did not consider fully the environmental impacts associated with implementing CCS technology, its action in proposing this rule is arbitrary, capricious, and contrary to the factors set forth in Section 111.
See preamble Section V.O.3.
CCS results in more CO2 emissions
Commenter (10050) states the proposed standard is based solely upon one component of CCS -carbon separation and capture- whose disposition of the captured CO2 is outside the scope of the rule. CO2 emissions will actually increase because carbon separation and capture consumes a substantial portion of the plant's electrical generation output so the plant will have to be designed to be substantially larger to accommodate the load needed to operate the carbon separation and capture process. One comment (10017) states for decades, U.S. EPA has been promoting the benefits of energy efficiency (e.g., Energy Star) and it is inconsistent and wasteful for EPA to mandate a specific technology (CCS) that consumes a large power load in order to operate. Commenter continues that CCS is estimated to consume approximately 30% of the energy output of the plant, and CCS also increases the amount of traditional and hazardous air pollutants emitted from these plants. Commenter contends that EPA should also consider the impact of the additional excess emissions that will result from the deployment of CCS. 
Issues of parasitic load are addressed at preamble section V.O.2
Commenter 9195 states a 2009 peer-reviewed paper published in Environmental Science & Technology found that EOR as a method of sequestering CO2 leads to net increases in CO2 emissions. The paper, Life Cycle Inventory of CO2 in an Enhanced Oil Recovery System, found that when oil is produced "93% o/the carbon in petroleum is refined into combustible products ultimately emitted into the atmosphere." Commenter asks a. Does the Agency dispute this finding? If so please explain why. If not, explain how pairing carbon capture and sequestration with enhanced oil recovery wouldn't defeat the fundamental purpose of EPA's proposed rule, and b. The Agency's favorite example of the potential for partial CCS is the Kemper plant in Mississippi and its associated EOR project. In December, Denbury Resources told the Associated Press that without the Kemper plant "they would not be able to produce oil there otherwise." In EPA's model CCS case, the Kemper plant, the oil would not be produced without Kemper. In this light, wouldn't it be reasonable to assume that the CCS EOR project at Kemper could lead to a net increase in CO2 emissions?
Some commenters expressed concerns regarding the use of captured CO2 for CO2-EOR on a life-cycle basis. These commenters are mistaken and EPA has in fact thoroughly considered these factors in finalizing the rule. Most of those commenting on this issue reference the work by Jaramillo et al. (2009), However there is more recent work by Jaramillo and her colleagues, published in 2013, which has expanded on the 2009 work. The 2013 study compares the lifecycle GHG emissions from EOR operations using different sources for CO2 (assuming a 90% capture efficiency at the source in all cases) and to non-CO2-EOR methods. The 2013 study also includes a case of coal as a source of CO2 for EOR based on a reference coal IGCC plant with CO2 capture, which is described in the paper as the scenario of coal as a source of CO2 for EOR. Based on its assumptions, the 2013 study concluded that sources of CO2 derived from the scenario of coal as a source of CO2 for EOR result in about 31% lower net CO2 emissions per barrel of oil recovered compared to natural-source CO2-EOR. The paper further notes that if even 25% of the CO2 currently used for EOR came from the scenario of coal as a source of CO2 for EOR instead of natural CO2 sources, then approximately 5-6 million metric tons of CO2e would be avoided and sequestered per year. 

The EPA also notes that very important in the studies by Jaramillo and her colleagues, as well as other researchers that have investigated this topic, are the assumptions for CO2 utilization  -  the amount of CO2 needed to recover the incremental oil from CO2 -EOR  -  which then provides the basis for the amount of CO2 assumed to be stored in the reservoirs from the application of CO2-EOR; the quantity against which offsetting CO2 emissions is compared. A study by NETL   concluded that, by far, this was the most important parameter that can impact estimates of net emissions from CO2-EOR operations. Most studies use assumptions of CO2 utilization (and perhaps ultimately stored) as a result of CO2-EOR that are based on historical CO2-EOR operations. Most of these studies assume values for CO2 utilization on the order of 0.2 metric tons of CO2 per incremental barrel of oil recovered (Jaramillo assumed values ranging from 0.15 to 0.22). Current EOR operations in the Permian Basin have typical utilization values of 0.4 metric tons of CO2 per barrel of oil recovered. Alternative assumptions about CO2 utilization can result in significant increases in the volumes of CO2 stored per barrel of oil recovery, and thus result in a significantly greater amounts of CO2 avoided and sequestered associated with CO2-EOR.
CO2-EOR has been successfully used for decades at many production fields throughout the United States, and is expected to continue for the foreseeable future. The decision to initiate or expand an EOR project is based on the economic viability of the specific project, and driven by broad market dynamics. In making a decision, EOR operators consider many cost components of the EOR project including engineering and design, new infrastructure development, electricity, and fuel costs in addition to the long term cost of purchasing CO2. These costs are balanced against the long-term demand for oil and the price owners or operators can receive for the additional oil produced throughout the lifetime of the project. EOR operators will obtain CO2 from the most cost effective reliable source to makes the project viable. New sources of natural CO2 are available and awaiting the right market conditions for development. Likewise, many new anthropogenic sources other than EGUs such as gas plants are available to support the oil industry's expansion of EOR as market conditions allow. Thus, the industry is not dependent solely on the CO2 from new EGUs complying with this rule to generate additional oil from EOR. Even if one thinks of CO2-EOR's oil as additive, the amount of oil produced through EOR with captured CO2 from new EGUs would vary by project but would likely have a negligible impact on the overall demand for oil, and CO2-EOR provides a net GHG emissions benefit compared to non-CO2-EOR oil production processes due to the amounts of CO2 stored with CO2-EOR.
Commenter 10662 states the World Nuclear Association, in an article titled "Clean Coal" Technologies, Carbon Capture and Sequestration (Updated February 2014) acknowledges Coal is an extremely important fuel and will remain so. Some 23 percent of primary energy needs are met by coal and 39 percent of electricity is generated from coal. About 70 percent of world steel production depends on coal feedstock. Coal is the world's most abundant and widely distributed fossil fuel source. The International Energy Agency (IEA) expects a 43 percent increase in its use from 2000 to 2020. It goes on to state: The energy penalty of CCS is generally put at 20-30 percent of electrical output, though since no full commercial systems are yet in operation, this is yet to be confirmed. Commenter continues that an analysis of the energy penalty of post-combustion CCS, based on the thermodynamic principles that result in the energy penalty, found an absolute lower bound for the energy penalty of ~11 percent and concluded it would be difficult to improve the energy penalty for post-combustion CCS to below ~ 25 percent in practice. 
Commenter states that if a 500 MW power plant must bear a 30% parasitic load associated with operations of a partial CCS system, then it must be designed to produce 650 MW - the 500 MW to meet consumer demand, and an additional 150 MW to support the 30% energy penalty of the CCS system. The increase in capacity will result in greater emissions. Even if the CCS system is successful in capturing 30% of the increased CO2 emissions from the higher capacity EGU, enabling it to operate at EPA's 1,100 lb/MWh emissions rate, the increase in emissions due to the increase in EGU capacity would result in a very small net decrease in CO2 emissions - less than 10% - while increasing the cost of construction and operation of the EGU by 80%. Nonetheless, EPA maintains that the proposed rule does not constitute a significant energy action as defined in Executive Order 13211 because it is not likely to have a significant adverse effect on the supply, distribution, or use of energy. EPA states that [t]his proposed action is anticipated to have negligible impacts on emissions, costs, or energy supply decisions for the affected electric utility industry. This statement and EPA's other contentions regarding energy penalty are in clear conflict with DOE's projections, raising the obvious question as to whether and how EPA can discount the opinions of DOE experts while claiming to have thoroughly and objectively evaluated all scientific considerations. Commenter states this is an indefensible position. 
See preamble Section V.O.2.
Commenter 4711 strongly urges EPA to resist the notion that it is necessary or appropriate to quantify the magnitude of "secondary" emissions associated with energy of compression because it would be an extraordinarily complex exercise since power on the grid is fungible and unless a storage resource is directly coupled to a specific generator, the electrons flowing to the compressor are not traceable. Second, EPA makes no effort to address such secondary emissions for any other technology - for example, the CO2 emissions associated with transportation of natural gas from the wellhead through the pipeline, and ultimately to a gas fired generating unit.
Commenter 8501 states recent studies have shown that when you consider the losses and leaks of methane, a highly potent GHG compared to CO2, from the methane extraction and distribution process, the overall CO2 equivalent benefit of widespread adoption of NGCC is minimal and worse than new energy efficient coal generating facilities that can reduce GHG emissions by more than one third compared to the existing coal fleet.
Commenter 8024 states increased dependence on natural gas could be counterproductive due to the long-term effects of methane leakage from gas exploration, production, transportation and generation. Commenter explains describes and analysis performed where the result was that when gas replaces coal there is additional warming out to 2050 with an assumed leakage rate of 0%, and out to 2140 if the leakage rate is as high as 10%. The overall effects on global-mean temperature over the 21st century, however, are small. The most important result, however, in accord with the above authors, is that, unless leakage rates for new methane can be kept below 2%, substituting gas for coal is not an effective means for reducing the magnitude of future climate change. This is contrary to claims such as that by Ridley (2011) who states, with regard to the exploitation of shale gas, that it will accelerate the decarbonisation of the world economy. The key point here is that it is not decarbonisation per se that is the goal, but the attendant reduction of climate change. Indeed, the shorter-term effects are in the opposite direction. Given the small climate differences between the baseline and the coal-to-gas scenarios, decisions regarding further exploitation of gas reserves should be based on resource availability (both gas and water), the economics of extraction, and environmental impacts unrelated to climate change. 
Commenter 10662 states the proposal does not address the impact of methane emissions from the use of natural gas and the resulting possibility of additional regulation of the natural gas industry. The proposal assumes an overall decrease in CO2 emissions resulting from a shift to natural gas units. The increased usage of natural gas for electricity will result in increased methane emissions due to leakage during production, transportation, and storage. Methane emissions, with their higher GWP, have a greater impact on climate change than CO2 emissions on a ton-for-ton basis.
Commenter 10662 states a recent article published in Science found measurements at all scales show that official inventories consistently underestimate actual CH4 emissions, with the NG [natural gas] and oil sectors as important contributors. Commenter adds that from an engineering standpoint, methane emissions cannot be fully contained and, because of methane's characteristics, have a correspondingly greater impact on overall CO2 emissions. Ironically, EPA's insistence on a fuel shift from coal to natural gas may very well increase negative environmental impacts on its own. In addition, public safety is already a huge concern with the increased burden to be imposed on already aging gas distribution infrastructure as a result of EPA's de facto selection of natural gas as its fuel of choice for electric generation. Commenter remarks that catastrophic conflagrations have already occurred because of the inadequacies of the existing system. When the system is subject to increased burden, the frequency and magnitude of these incidents will only increase, as evidenced by the recent explosion of the gas pipeline in Sissonville, West Virginia, which ignited and melted a section of Interstate 
Issues of parasitic load and EPA's evaluation thereof are found at preamble section V.O.2. Comments regarding increased methane emissions due to increased natural gas production (e.g. commenter 10662) are premised on the rule causing there to be more use of natural gas than would otherwise occur, and on uncontrolled leaks of methane in the process.  Neither of these assumptions are correct.  See RIA chapter 4 (NGCC use is increasing for reasons unrelated to the final standard of performance).  

Commenters expressed concerns regarding the use of captured CO2 for CO2-EOR on a life-cycle basis and referenced the work by Jaramillo et al. (2009). The EPA has in fact thoroughly considered these factors in finalizing the rule. There is more recent work by Jaramillo and her colleagues, published in 2013, which has expanded on the 2009 work. The 2013 study compares the lifecycle GHG emissions from EOR operations using different sources for CO2 (assuming a 90% capture efficiency at the source in all cases) and to non-CO2-EOR methods. The 2013 study also includes a case of coal as a source of CO2 for EOR based on a reference coal IGCC plant with CO2 capture. Based on its assumptions, the 2013 study concluded that sources of CO2 derived from the scenario of coal as a source of CO2 for EOR result in about 31% lower net CO2 emissions per barrel of oil recovered compared to natural-source CO2-EOR. The paper further notes that if even 25% of the CO2 currently used for EOR came from the scenario of coal as a source of CO2 for EOR instead of natural CO2 sources, then approximately 5-6 million metric tons of CO2e would be avoided and sequestered per year. 

The EPA also notes that very important in the studies by Jaramillo and her colleagues, as well as other researchers that have investigated this topic, are the assumptions for CO2 utilization  -  the amount of CO2 needed to recover the incremental oil from CO2 -EOR  -  which then provides the basis for the amount of CO2 assumed to be stored in the reservoirs from the application of CO2-EOR; the quantity against which offsetting CO2 emissions is compared. A study by NETL   concluded that, by far, this was the most important parameter that can impact estimates of net emissions from CO2-EOR operations. Most studies use assumptions of CO2 utilization (and perhaps ultimately stored) as a result of CO2-EOR that are based on historical CO2-EOR operations. Most of these studies assume values for CO2 utilization on the order of 0.2 metric tons of CO2 per incremental barrel of oil recovered (Jaramillo assumed values ranging from 0.15 to 0.22). Current EOR operations in the Permian Basin have typical utilization values of 0.4 metric tons of CO2 per barrel of oil recovered. Alternative assumptions about CO2 utilization can result in significant increases in the volumes of CO2 stored per barrel of oil recovery, and result in significantly greater amounts of CO2 avoided and sequestered associated with CO2-EOR.

CO2-EOR has been successfully used for decades at many production fields throughout the United States, and is expected to continue for the foreseeable future. The decision to initiate or expand an EOR project is based on the economic viability of the specific project, and driven by broad market dynamics. In making a decision, EOR operators consider many cost components of the EOR project including engineering and design, new infrastructure development, electricity, and fuel costs in addition to the long term cost of purchasing CO2. These costs are balanced against the long-term demand for oil and the price EOR owners or operators can receive for the additional oil produced throughout the lifetime of the project. EOR operators will obtain CO2 from the most cost effective reliable source to make their projects viable. New sources of natural CO2 are available and awaiting the right market conditions for development. Likewise, many new anthropogenic sources other than EGUs such as gas plants are available to support the oil industry's expansion of EOR as market conditions allow. Thus, the industry is not dependent solely on the CO2 from new EGUs complying with this rule to generate additional oil from EOR. Even if one thinks of CO2-EOR's oil as additive, the amount of oil produced through EOR with captured CO2 from new EGUs would vary by project but would likely have a negligible impact on the overall demand for oil, and CO2-EOR provides a net GHG emissions benefit compared to non-CO2-EOR oil production processes due to the amounts of CO2 stored with CO2-EOR.
Should evaluate control technology, not fuel switching, for cost effective analysis
Commenter 10239 states that rather than addressing the real-world costs and benefits of requiring coal-fired EGUs to install CCS, the EPA prepared several models which show that coal-fired EGUs will not be cost-effective. Commenter states that the EPA must evaluate the costs and benefits of the emission control technology it has proposed, not the costs and benefits of fuel switching. Commenter adds that rather than assessing the costs and benefits of the CCS programs in the planning or construction phases, the EPA only completes a cursory analysis of the costs and benefits of partial CCS by relying on preexisting RIAs, and a NETL cost assumption model. Commenter adds that the EPA's cursory analysis shows that the costs of requiring CCS are likely to exceed the benefits. 

Commenter 10098 states  EPA's decision to not engage in a substantive cost benefit analysis or economic impact analysis Is arbitrary and capricious, explaining that  EPA is wrong that no new sources will be impacted by the NSPS proposal. Commenter continues that EPA acknowledges in the proposed rule that companies may consider constructing new coal-fired EGUs, and EPA cannot simply ignore the additional costs that will be imposed on such facilities if CCS is required for all new coal-fired EGUs.  Commenter 10098 adds that  instead of conducting a full cost benefit analysis that addresses the actual, real-world  costs and benefits of requiring CCS for coal-fired EGUs, EPA compares a number of models which allegedly show that coal-fired EGUs will not be cost-effective when compared to alternative energy sources such as NGCC or nuclear. But these comparisons miss the point. EPA must consider the costs and benefits of requiring partial CCS for new coal-fired EGUs, not the costs and benefits of switching to a new fuel source.
There is no requirement in section 111 (a) agency to engage in cost-benefit analysis.  The broad delegation to take cost into account eschews any particular method or metric for doing so.  The D.C. Circuit has in fact held, since the inception of the section 111 program, that cost-benefit analysis is not required when considering costs under section 111 (a).  Portland Cement I, 486 F. 2d at 387.  EPA has evaluated costs permissibly and reasonably on both a per-plant and national basis.  See preamble section V.H. and I.  Modeling the EPA performed for this rule also projects that, even in the absence of this action, new fossil fuel  -  fired capacity constructed through 2022 and the years following will most likely be NGCC capacity that complies with the final standards.  This is due to current and projected economic market conditions.  See generally RIA chapter 4.  Nonetheless, there could be circumstances where new coal-fired capacity is built  -  commenters to EPA's initial proposal maintained adamantly that this was a possibility (although no specific examples have as yet been provided).  In that event, EPA conducted further analysis which shows that there would be net quantified monetary benefits to society in the form of reduced CO2 emissions and secondary fine PM emissions from SCPC facilities (due to reduced SO2 emissions).  See RIA chapter 5.2.  That is, for each new SCPC facility that would be constructed, the cost of meeting a 1400 lb/MWh-gross standard is more than offset by the monetized benefits of the CO2 and secondary fine PM under a range of conditions. This analysis does not quantify other benefits of the standard (e.g. reductions in direct SO2 emissions, reductions in coarse PM emissions).  
BSER availability, reliability, reasonable cost
Commenter 10395 states that the proposed NSPS for coal-fired EGUs requiring carbon capture is not supported by the existing state of carbon capture technology as applied to EGUs, and EPA does not have the discretionary authority to impose it in the way proposed in this rulemaking. Commenter explains that EPA argues that it does not rely solely on these projects, and among the projects that EPA uses to claim that its "rationale does not depend solely upon those projects" are two projects that Basin Electric either owns (Dakota Gas) or is familiar with (SaskPower's Boundary Dam CCS Project in Estevan, Saskatchewan); however, neither of these projects can fairly be cited as evidence of the viability or cost effectiveness of IGCC with carbon capture.

Commenter9194 states that EPA is exercising authority not granted to it by Congress regulating fuel choice and the means of energy production rather than regulating emissions reductions.  Commenter states that it is the view of industry experts that EPA's partial CCS requirement for coal plants will in effect serve as a ban to new coal plants in the U.S. since EPA is mandating an emerging technology that is mislabeled as a next-of-a-kind technology. EPA provides no analysis or discussion of the very serious repercussions - economic, energy security, reliability - of essentially banning new coal plants in the U.S. and increasing reliance on natural gas. 
Commenter 10046 states the costs associated with the NSPS are economically unreasonable, explaining that Section 111(a)(1) mandates that, in setting a standard of performance, EPA must take into account the cost of achieving such reduction, and conclude that such costs are reasonable.  Portland Cement Assn, 486 F.2d at 378. EPA advances two illogical syllogisms to declare that CCS costs are reasonable, and then puts an unlawful gloss on those syllogisms by focusing on national costs and not unit costs. Commenter 10046 states EPA's cost analysis is not consistent with the statutory requirements and EPA's established pattern of practice in evaluating cost reasonableness. The case law in the District of Columbia Circuit indicates that costs can be considered reasonable provided they are not excessive or exorbitant, but EPA's actual practice in determining the reasonableness of BSER costs historically has required a careful assessment of how the costs of EPA's proposal will actually affect the financial health of the industry. For example, after remand for further economic assessments of the NSPS for cement kilns, the District of Columbia Circuit upheld the standard against cost objections because that industry ha[d] not shown inability to adjust itself in a healthy economic fashion to the added costs of control technology. The effects to be assessed have included not only those impacts on the coal-fired power plant industry, but also on coal mines themselves. Legislative history reveals that Congress - 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. Thus, Congress indicated that it wanted assurances from EPA that the new standards would not exacerbate existing problems, e.g., produce adverse effects on the coal market, impediments to long term growth, and inhibition of technological innovation  
Commenter continues (10046) that the effects of NSPS proposals on the economic health and viability of the industry have traditionally been the key focus of EPA assessments under EPA's historical approach to NSPS. EPA has carefully assessed whether the costs are within the range that could be absorbed while not unduly depressing economic viability, including whether or not they could in fact be passed on, citing the following NSPSs Pressure Sensitive Tape and Label Surface Coating Industry; Kraft Pulp Mills; Basic Oxygen Process Furnaces; Beverage Can Surface Coating Industry; Synthetic Organic Chemical Manufacturing Industry; Coal Preparation Plants;  Commenter remarks (10046) that when EPA has concluded that the industry, or a segment thereof, would not be capable of absorbing or passing on the costs, it has found them to be unreasonable, citing three standards: Nonmetallic Mineral Processing Plants; Petroleum Dry Cleaners; Onshore Natural Gas Processing.  Commenter 10046 states EPA's economic analysis in the proposal does not stand up to its own criteria. In some contexts it might be possible for EPA to show that such a cost increase would not affect plant viability or could easily be passed along to the customer, or would not preclude construction of new coal-fired plants or have unreasonable impacts on the economic feasibility of a new coal plant, or would not have an unreasonable impact on the future growth of the industry, but EPA has made no such showing here. As EPA notes, the alternative to a new coal plant is a new gas plant (that incurs no NSPS costs). But the cost of a new gas plant is already $33/MWh cheaper than a new coal plant. Now, EPA would propose to add another $18/MWh to that existing cost differential, insouciantly stating that this is only about half the additional cost of coal-fired generation, compared to natural-gas fired generation. The conclusion that this cost adder is reasonable is inappropriate. The District of Columbia Circuit would be wholly unable to conclude, as it would be required to do, that the coal-fired power plant industry has the ability to adjust itself in a healthy economic fashion to these additional costs. EPA has no evidence that these costs can be easily passed along to the consumer, or that they can plausibly be absorbed without affecting industry structure or profitability.
Commenter 10046 states EPA's traditional pattern of practice, as noted above, when confronted with an economically-stressed industry or industry segment that is simply in no position to bear additional economic costs has been not to regulate that portion of the industry on grounds of economic unreasonableness. The addition of an 18 percent cost adder to the existing cost differential between coal and gas plants will necessarily have significant adverse impacts on the economic viability of new coal plants. Nor can EPA claim that the large price differential between EPA's asserting that existing market conditions (e.g., cheaper gas units) have already caused the market for new coal plants to founder, even in the absence of the partial CCS requirement, does not eliminate EPA's obligation. Such an interpretation of the economic prong of Section 111 would be unreasonable, if only because EPA's ability to add whatever costs it wants would be unbounded.
In response to commenter 9194, the final standard does not mandate any particular type of compliance  -  only that a new fossil fuel-fired steam electric plant emit less than 1400 lb. CO2 MWh.  There are a number of potential compliance pathways for doing so.  CCS is not mandated.  IGCC is not mandated.  The final standard of performance can be achieved without either.
Commenter 10395 claims that neither Dakota Gasification or Boundary Dam shows that the CCS technology used at either plant is demonstrated
EPA disagrees.  See preamble sections V.D. and E.
Commenter 10046 challenges EPA's consideration of cost.  The commenter indicates that a proper consideration of cost requires EPA take into account the impact of the rule on the industry's economic health.  Looked at in this perspective, the commenter maintains that cost increases associated with partial CCS necessarily impact industry health adversely because the cost increase exacerbates the already considerable difference between coal and natural gas prices.  The commenter further maintains that arguing that coal is already uncompetitive proves too much because it would allow imposition of any standard.
The agency has considered these arguments carefully.  As to the legal point, economic health to the industry is one metric by which to evaluate costs, and the agency has found here that the rule has little effect on the industry because, under the base case modeling the EPA performed for this rule, even in the absence of this action, new fossil fuel  -  fired capacity constructed through 2022 and the years following will most likely be NGCC capacity that complies with the final standards.  This is due to current and projected economic market conditions, not to the final standard of performance.  See generally RIA chapter 4.  Even this commenter documents the large difference between coal and natural gas prices that exists now.  If new coal capacity is to be added, it will therefore be for a reason not cost-driven, but for other reasons, for example, to preserve fuel diversity, or as a hedge against price increases of other fuels.  In this case, the chief non-NGCC baseload dispatchable technologies would be coal and nuclear, and the EPA has carefully examined and structured the final standard of performance so that these two technologies remain price competitive.  See generally preamble chapter V.H.5. This analysis, and methodology, is responsive to the commenter's (correct) point that costs of any magnitude cannot be imposed simply because the industry is already non-competitive with a principal competitive fuel.  Indeed, if the EPA were espousing that reasoning, it would select full CCS as BSER or a standard predicated on a higher percentage of partial CCS, but is not doing so for reasons of cost (full CCS is demonstrated, and working well at the Boundary Dam facility).  
Proposed BSER requiring partial carbon capture has not been adequately demonstrated because the system of emission reduction is excessively costly 
Commenter 10097 states the proposed BSER requiring partial carbon capture has not be adequately demonstrated because the system of emission reduction is excessively costly. The proposal references three Department of Energy (DOE) studies to access cost and performance of coal and natural gas EGUs. The most recent one addresses carbon capture. EPA relies exclusively on these studies to predict the levelized cost of electricity (LCOE) for SCPC and IGCC EGUs, including LCOE costs for no carbon capture, partial carbon capture and full carbon capture alternatives. Table 6 in the proposal summarizes the LCOE costs based on these studies. Id. EPA relies on these LCOE cost data to conclude that cost of partial carbon capture as BSER is reasonable. As the enclosed report (A Review of the technical and costs basis supporting proposed performance standards for greenhouse gas emission from new electric utility generating units, Cichanowicz, J. Edward (prepared by commenter's consultant clearly denotes, there are fundamental problems with EPA's reliance on these studies and the resultant calculated LCOE to determine BSER is reasonably costly in the context of rational rulemaking. Commenter adds that EPA cannot reasonably rely on Table 6 LCOE data that are based the theory that as technology matures with the construction of successive plants, the cost decreases. 
See response 3.3-16a above.
Commenter 10952 states that the proposed BSER requiring partial carbon capture has not been adequately demonstrated because the system of emission reduction is excessively costly. Commenter states that CAA Section 111 (a)(1) requires costs of achieving emission reductions be taken into account when determining BSER, but the statute is silent regarding what the appropriate level of BSER cost is permissible. The commenter agrees with EPA that upon review of the relevant case law costs must meet a "reasonableness" standard. Regarding determining BSER cost reasonableness on a facility basis, the proposal cites Portland Cement 486 F.2d 375, 387 where the court determined that a capital cost increase of 12 percent coupled with an operating cost increase of 5-7 percent for a new facility to accommodate BSER to meet an NSPS was acceptable. Id. Also the proposal cites legislative history that the applicable technology costs be considered "a normal and proper expense of doing business." 
Commenter 9602 states that EPA did not conduct proper peer review of CCS technologies or examine the possible cross-media impacts to water and soil as required under the National Environmental Protection Act (NEPA).  
In response to commenter 10952, the EPA does not read the first Portland Cement case to create an upper bound on what price increases can be considered reasonable.  The NSPS adopted here is within the same range of capital cost increase adopted for this industry in other NSPS, which have been judicially sustained.  In response to commenter 9602, by statute, NEPA does not apply to CAA actions.  The EPA carefully considered environmental impacts, as required by section 111 (a).  See preamble Section V.O.2.
Questioning CCS viability as a control technology
Commenter (9472) states the costs of CCS would be so excessive that they would preclude new coal-fueled power plants from being developed in the future. Imposing such unreasonable costs is contrary to the Clean Air Act, as interpreted by the courts. EPA has a duty not only to consider costs, but also to set a performance standard under section 111(b) that is not cost prohibitive for new coal-fueled power plants. In Portland Cement Assn. v. Ruckelshaus, 486 F.2d 375 (D.C. Cir. 1973), the court remanded EPA's NSPS for Portland Cement plants so that EPA could consider whether "the standard as adopted unduly precludes supply of cement, including whether it is unduly preclusive as to certain qualities, areas, or lowcost supplies." The D.C. Circuit also has underscored how intertwined achievability and costs can be stating that "the statutory standard is one of achievability, given costs" and that "[s]ome aspects of 'achievability' cannot be divorced from consideration of 'costs.'" Natl. Lime Assn. v. EPA, 627 F.2d at 431. Commenter states that CCS is costly and may not be economically viable even with governmental subsidies and revenue from EOR.  Comment states CCS projects have either been cancelled or are struggling to be developed and may never be built due to financial challenges or major cost overruns. Given that little or no additional governmental funding is expected to support CCS projects in the future, EPA is effectively proposing to establish a CO2 performance standard that no company can afford to meet and imposing costs greater than utilities and their customers can bear, concluding that the imposition of such costs is contrary to the requirements of the CAA, as interpreted by the courts. Commenter adds that EPA's cost analysis expects EOR revenues from the sale of the CO2 to range from $20 to $40 per ton of CO2, and, by contrast, the incremental costs of CCS could range from $60 to $100 per ton of CO2 captured. Commenter concludes this cost comparison demonstrates that EOR revenues cannot bridge the increased costs that would be incurred from the CCS requirement. Commenter states EPA's assumptions on the potential revenue stream generated from the sale of CO2 emissions to EOR operators are high, and that the opportunity to secure EOR revenues would be unavailable for many new CCS projects due to location constraints. Commenter adds that recent reports indicate that EOR operators could be unwilling to purchase CO2 from new coal-fueled power plants with CCS given that the EOR operator will be required to comply with the monitoring and reporting requirements under Subpart RR of the GHG reporting rules. 
Commenter 10083 states EPA's factual and legal foundations for its proposed standards is flawed and should take into account the impact of eliminating coal as a generation option.  As discussed below, WEST asserts that EPA has not appropriately followed a correct interpretation of BSER in basing a standard of performance on CCS.  EPA's assertions regarding current costs and benefits of its proposed standards are selective and do not paint the whole picture. The foundation for EPA's proposed GHG NSPS is based on a premise that few if any solid fossil fuel-fired EGUs will be built in the foreseeable future thereby resulting in negligible CO2 emission changes, quantified benefits, and costs by 2022. While this may be valid in the short run, the long term resource planning impacts of limiting fuel diversity without fully mature alternatives could be significant.  EPA's proposed rule forecloses utility options to build coal-fired power plants in order to manage fuel costs for customers. EPA's CCS mandate on new coal-fired EGUs permanently forecloses the utilities from switching between gas and coal fuels to allow market forces to lower fuel costs. Requiring coal plants to essentially meet an emission standard equivalent to the emission standard established for natural gas-fired EGUs through the required use of CCS, before that technology has been demonstrated as a reliable, commercially viable technology, will impose up to an 80% increase in the cost of coal generated electricity. This removes fuel cost hedging capability from the coal generation resource and will permanently remove fuel market forces as a strategy for managing fuel costs for utility generation resources. 
The final standard of performance does not "unduly preclud[e] supply of [coal], including whether it is unduly preclusive as to certain qualities, areas, or low cost supplies."  The standard is not geographically limited, can be met using coal plus co-firing natural gas (thus preserving commenter 10083's objective of preserving fuel switching options), and can be met without regard to type of coal used.  References to cost increases based on DOE testimony are misplaced, since that testimony was with regard to full CCS, which the EAP has rejected as too costly to be BSER.
No demonstration that CCS is viable through BACT determinations
Commenter 9774 states that the EPA's analysis of CCS for this proposal is not consistent with establishing NSPS requirements under the CAA, stating that there are no installations of CCS that have been determined feasible or cost-effective under best available control technology (BACT) or have been required under any other regulation for fossil fuel power plants. Commenter states that there are few installations of CCS operating to provide CO2 for industrial purposes and that in all other cases, CCS is being installed or operated in conjunction with Department of Energy funding. Commenter states that CCS has not been shown to be viable through BACT determinations and, therefore, should not be required under the proposed NSPS requirement.

Commenter 8937 states first and foremost, customers demand reliable electricity at a reasonable cost. CCS is routinely rejected in GHG BACTs due to the costs and parasitic load impacts. DOE Assistant Secretary for Clean Coal Julio Freedman testified before the House Energy and Commerce Committee, stating that first generation CCS technology will result in a 70-80% increase in the wholesale price of electricity. Commenter closes, stating customers wouldn't pay for such a unit and public utility commissions wouldn't approve it-and no competitive wholesale electricity market would bear such costs.
See preamble Section XII.C.  DOE Assistant Secretary Freedman's testimony addressed full, not partial, CCS.

Lack of Benefits
Arbitrary and capricious - rule will not reduce emissions deemed significant 
Several commenters (10098, 10087, 10087, 10034, 9666, 9666, 9780, 10680, 9725, 10087, 7977, 10607, 10963) challenged EPA's application basis approach under Section 111(b).  Commenter (10098) states that even if EPA could apply a rational basis approach under Section 111(b), its application here is arbitrary because EPA does not establish that the rule will reduce the emissions that it deems significant. While EPA asserts that "a single new coal-fired power plant may amount to millions of tons [of CO2] each year," 79 Fed. Reg. at 1455, this alone cannot provide a rational basis for making endangerment and significance findings or for issuing a GHG NSPS for coal-fired EGUs. EPA must also show that, by issuing regulations, it will reduce those emissions and that the reduction will ameliorate the endangerment at issue. EPA asserts that the rule will have no effect at all on CO2 emissions because no coal-fired EGUs will be constructed anyway. In addition, EPA's rulemaking authority is limited to "prescribe[ing] such regulations as are necessary to carry out" the Administrator's functions under the CAA. (CAA section 301(a)) Commenter states that a rule that will have no effect on air emissions and that produces no benefits (or costs) of any kind cannot be considered "necessary" under any interpretation of the Act and concludes that the EPA's application of its rational basis approach is arbitrary, capricious, and not in accordance with the law.
Commenter (9666) states that neither the RIA chapter describing climate change nor any other part of the RIA connects the proposed rule to any effects on climate change. Commenter states that EPA never asserts that the proposed rule will either reduce GHG emissions or alleviate EPA's projections of climate change effects. They state that, to the contrary, EPA states that the proposed rule "is not anticipated to have a notable effect on the supply, distribution, or use of energy," and "will result in negligible CO2 emission changes . . . by 2022." They state that this statement contradicts other language in the preamble that states that because the section 111(b) proposal "serve[s] as a necessary predicate" for the regulation of CO2 emissions from existing EGUs under section 111(d), "the proposed rule will contribute to the actions required to slow or reverse the accumulation of GHG concentrations in the atmosphere." They state that EPA is advancing mutually inconsistent arguments in support of the proposed rule.
They state further (9666) that fundamentally, a rule that has no benefits exceeds the Agency's authority under the Act. See CAA Section 301(a) (authorizing the Administrator to promulgate only "such regulations as are necessary" to carry out her functions under the Act).
Commenter (9780) remarks that EPA states in the RIA that the proposed standards, including the proposed standards that are based on CCS, will not result in any GHG emissions reductions. This is because both EPA and EIA predict that the vast majority of new generating capacity that will be built through 2030 will be natural-gas based. Commenter states that this projection is not based on assumptions about new CO2 limits, but is driven instead by projected fuel costs and other regulatory requirements on new coal-based EGUs. Commenter states that accordingly, EPA could select any other control technology or system for new coal-based EGUs and achieve the same result (no additional emissions reductions) and conclude that EPA cannot rely on the size of emissions reductions related to CCS as justification for finding that partial CCS is BSER, or for the rejection of other systems of emissions reduction on coal plants. Moreover, they add, EPA cannot logically argue on one hand that there are no cost impacts of the Proposal because no new fossil-based EGUs will be built under the proposed standards, but in the next breath argue that stringent standards are needed to secure significant emissions reductions.
The commenter is not correct that the final standards of performance are without benefits.  It is correct that the base case modeling the EPA performed for this rule projects that, even in the absence of this action, new fossil fuel  -  fired capacity constructed through 2022 and the years following will most likely be NGCC capacity that complies with the final standards.  This is due to current and projected economic market conditions.  See generally RIA chapter 4.  Nonetheless, there could be circumstances where new coal-fired capacity is built  -  commenters to EPA's initial proposal maintained adamantly that this was a possibility (although no specific examples have as yet been provided).  In that event, EPA conducted further analysis which shows that there would be net quantified monetary benefits to society in the form of reduced CO2 emissions and secondary fine PM emissions from SCPC facilities (due to reduced SO2 emissions).  See RIA chapter 5.2.  That is, for each new SCPC facility that would be constructed, the cost of meeting a 1400 lb/MWh-gross standard is more than offset by the monetized benefits of the CO2 and secondary fine PM. This analysis does not quantify other benefits of the standard.  The standard provides certainty for new plants (see, for example, the AEP FEED study associated with the Mountaineer project, where the company states that it was abandoning the project due in part to regulatory uncertainty), and a means to enable carbon control technology that will allow future coal  -  fired capacity in a reduced carbon economy.  The commenters are also correct as a matter of law that some type of section 111 (b) standard is a legal condition precedent to section 111 (d) guidelines for existing sources, but this rule has positive benefits with or without consideration of that additional factor.   Power plants are the largest domestic source of carbon pollution. While companies building power plants today are already making cleaner generation choices, such as natural gas combined cycle or coal with CCS, the proposed rule would lock in a lower carbon future and make sure this progress continues.  The plants built under this standard would be cleaner than the average coal unit operating today  -  which emits over 4 million metric tonnes of CO2 a year. By comparison, a new natural gas plant would emit 1.7 million tonnes a year, or about 2.3 million metric tonnes less; and a new, modern coal unit would emit no more than 3 million tonnes per year, or about 1 million tonnes less.
The primary conclusion of the Regulatory Impact Analysis was that there will be negligible costs as a result of the regulation. In addition to the primary analysis, the Regulatory Impact Analysis for the rule also included several illustrative analyses, examining the costs of the rule under a range of natural gas prices and the cost associated with building a coal plant with CCS. This analysis found that, while there are additional costs to building a coal-fired power plant with CCS, there are also climate and human health benefits, as well as potential for revenue from enhanced oil recovery.  These quantified benefits exceed regulatory costs under a range of assumptions.
Commenter 8501 states EPA should not adopt a costly rule that provides no environmental benefits, discourages technological development, and creates negative environmental impacts, and adds that the rule is unnecessary if it creates no benefit. 
Commenter 10087 states EPA states that it is "proposing new standards of performance for new affected fossil fuel fired electric utility steam generating units and stationary combustion turbines", but EPA provides no justification for these standards of performance.
Commenters 10239, 9770, 9666 state the EPA inappropriately asserts that the cost differential between electricity generation via natural gas and coal will dictate that only natural gas units will be constructed until after the next NSPS review cycle is complete, and, in the absence of any new coal-fired EGU capacity, the EPA concludes that the proposal will have no costs or benefits (79 Fed. Reg. at 1,433; RIA at 5-1), and, in turn, did not conduct full cost-benefit and economic impact analyses. 
Commenters 10239 states the EPA's assumption that no new sources will be impacted by the NSPS proposal is incorrect and cites a NERA report (attached to comments) that evaluated the likelihood that new coal-fired EGUs would be built under a variety of future development scenarios developed by the U.S. Energy Information Administration (EIA) for its Annual Energy Outlook. Based on these scenarios, NERA concludes that economic conditions in one or more regions in the United States likely would make some number of new coal-fired builds without CCS a preferred economic choice in the near future, over other alternatives, including natural gas builds. NERA at 1.  Commenter adds specifically, under each EIA scenario, NERA found that some coal-fired EGUs would be built in the absence of the proposed rule. Under one scenario, with a planning and construction period of six to eleven years, facilities could decide in the near term whether to add additional coal-fired EGU capacity absent the NSPS restrictions. And those projects could commence even sooner, depending on other changes to current market conditions. Commenter concludes that, contrary to the EPA's assertions, new coal-fired EGUs will remain a viable option in the absence of the proposed rule. As a result, the EPA's not conducting a complete cost-benefit analysis for the proposed rule is arbitrary, capricious, and unlawful.
Commenter 9201 states EPA's cost benefit analysis should be robust, explaining that EPA's entire analysis of economic effects and energy requirements rests upon a single assumption---no new coal-fired EGUs without CCS would be built even in the absence of the proposed standard. By requiring unproven and exorbitantly expensive CCS technology, the EPA's "no new coal-fired EGUs" prediction becomes a reality. Commenter states EPA does not explain explicitly why the CCS-conditioned standard for new coal-fired EGUs is even necessary if no new coal EGUs will be built during the analysis period (through 2022). 
 A standard aligned with the performance of high performance SCPC and IGCC (or even no standard), would result in the same impacts as the proposed standard---no measurable CO2 emission changes---and leave a valuable generation option available if EPA's economic effects and energy requirements assessment prove incorrect. Moreover, commenter states the agency would still retain the option under the CAA of revisiting and changing a SCPC and IGCC without CCS standard if CCS technology became adequately demonstrated and economically viable in the meantime.  
Commenter 9201 states EPA largely relies upon EIA forecasts reflected in the in EIA's Annual Energy Outlooks from 2009-2013; however, there are several significant and fundamental problems with using EIA's modeling and forecasts, including first, natural gas supply, price and power sector consumption, and overestimating the supply capabilities of the natural gas network and underestimating the price response results in a substantial underestimate of the potential costs of EPA's proposal. Second, the forecasts used in the EPA RIA do not account for the changes in the electric fleet composition described earlier and forecasts do not reflect EIA's recent adjustments to the coal and nuclear retirements, nor the price response recently experienced over the past two years that exceed EIA's prior forecasts. Commenter continues that forecasts also do not reflect new demand projections from the conversion of more of the transportation fleet to compressed natural gas or the export of liquefied natural gas to international markets. 
Several commenters (9396, 9396, 9033, 3236, 1681, 8911, 10036, 3358, 6870, 10294, 9194, 10928, 2658, 9649, 10023, 10023, 10392, 4710, 10024, 10046, 10046, 9602, 9602, 9505, 9505, 10086, 10951, 9190, 10048, 10028, 9423, 3593, 10374, 10952, 9650, 1898, 9772, 8024, 10607, 10880, 10555, 9765, 9396) state EPA has proposed a rule for which EPA cannot identify any direct benefits and which EPA concedes would not result in a decrease in CO2 emissions. Commenters are compelled to ask what value is achieved from issuing a rule that has no benefits and does not reduce emissions. EPA asserts that, solely due to market forces, no new coal plants will be built. This assumption allows EPA to assert that the rule will, therefore, have no costs. However, it also results in EPA concluding the rule will provide no benefits. More fundamentally, EPA's decision to propose a rule that will not produce environmental, health or economic benefits raises grave concerns. Rulemaking without justification sets a dangerous precedent and has no basis under the Clean Air Act (CAA). Allowing regulators to write rules without regard to justification would confer on the federal government seemingly unfettered powers to constrain private sector economic and business decisions in a manner that could lead to very negative consequences.
Commenter 9487 states  EPA points to generalized risks such as "climate change"-a risk that exists independent of human activities-which EPA believes will result from increased greenhouse gas concentrations in the atmosphere. It has not shown how its chosen standards, or any standards governing U.S. power plants, would meaningfully address the climate-related effects it invokes as the basis for regulation. And this relieves it from an essential constraint on agency action-that agencies show their chosen level of regulation is the least restrictive means to achieve stated public health goals. Commenter closes that EPA's own predictions about its performance standards' (in)efficacy illustrate how far the proposal diverges from precedent and statute.
Commenter 10391 continues EPA's reading would absolve it from providing a rational basis for the Proposed Rule, explaining that an agency provides no rational basis for regulation absent a showing that its proposed rules will have a meaningful effect on the problems it's trying to address. Here, EPA declines to show any effect from its rules, much less a meaningful one; indeed, EPA concedes that the rules as proposed will have no effect: "[T]he proposed rule will result in negligible CO2 emission changes." Here, EPA points to generalized risks such as "climate change"-a risk that exists independent of human activities-which EPA believes will result from increased greenhouse gas concentrations in the atmosphere. EPA has not shown how its chosen standards, or any standards governing U.S. power plants, would meaningfully address the climate-related effects it invokes as the basis for regulation. And this relieves it from an essential constraint on agency action-that agencies show their chosen level of regulation is the least restrictive means to achieve stated public health goals. Indeed, its own predictions about its performance standards' (in) efficacy illustrate how far the proposal diverges from precedent and statute. 
Commenter 8911 posits the Proposed Rule is ineffective largely because the Proposed Rule would unreasonably: 1. allow very inefficient plants (especially simple cycle units and small capacity units) to operate at very high emission rates while operating at inexplicably high capacity factors, 2. discourage future power projects from proposing the maximum practical plant efficiency (i.e. the lowest heat and CO2 emission rate) and 3. employ a compliance method that requires the NSPS of even very efficient plants to be unnecessarily high to accommodate the high uncertainty inherent in long term emission monitoring. In response, commenter offered the following NSPS formula as a more effective and reasonable alternative: NSPS (lb. CO2 / MWh) = 1,000 - {[(Maximum Allowed % CF - 25%) /25%] x 100} for CF levels ranging from 10% through 65% using emission calculations based on new and clean, base load performance tests that are corrected for plant back pressure and other ambient conditions as previously discussed. CF levels outside the range are unregulated. The following table illustrates the variable result of the proposed NSPS formula. Thus, if the plant is permitted to operate at 25% CF, then the applicable NSPS is 1,000 lb. CO2 / MWh. If the CF is limited to 50% CF, then the applicable NSPS would be 900 lb. CO2 / MWh. Capacity factors < 10% or > 65% would be exempt from the NSPS requirement. Commenter added that the most reasonable method of regulating compliance in the long term would be to reduce the capacity factor limit - for as long as a deficiency in plant maintenance is causing an increase in the emission rate. Maintenance reporting and remedies could be a part of the PSD permit for GHG. The proposed NSPS formula would motivate new power plant owners to further reduce the CO2 emission rate of new grid connected power plants in the U.S.A. without burdening utility rate payers with excess cost or diminished transmission grid reliability.
Commenter 8955 questions how the section, "A. Climate Change Impacts From GHG Emissions'' correlates with the later suggestion that negligible GHG emissions will occur until 2022? Please explain how the new rule relates the two (2) sections. The EPA also suggests that because of the proposed rule negligible CO2 emission changes, quantified benefits, and costs by 2022 will result. Commenter asks then to understand that after 2022 the CO2 emissions (GHG) will be forecast to decrease?
Commenter 9195 states Section 1-3 of NSPS Regulatory Impact Analysis, EPA stated that "even in the absence of this rule, existing and anticipated economic conditions will lead electricity generators to choose new generation technologies that meet the proposed standard without the need for additional controls."  Commenter asks a. If that is the case, why did EPA expend substantial resources adopting a rule that it asserts will have no impact on "new construction" of electric generation facilities?  b. EPA also states that it "anticipates that the proposed EOU New Source GHO Standards will result in negligible CO2 emission changes, energy impacts, quantified benefits, costs, and economic impacts by 2022." Why is EPA engaged in a regulatory proceeding for which EPA's own analysis states will result in "negligible, quantified benefits, costs, and economic impacts by 2022"? c. Why does EPA conclude that its NSPS proposal would "provide an incentive for supporting research, development, and investment into technology to capture and store CO2" if EPA predicts that, even absent NSPS, there would be no new "coal-fired power plant" construction and thus no need to "implement[t] some form of partial capture and storage" for such plants? d. What is the basis for EPA's recognition that "a few companies may choose to construct coal or other solid fossil fuel-fired units" in the absence of the proposed NSPS? See Section 1-3 of NSPS Regulatory Impact Analysis. Commenter 9195 continues: Is it EPA's position that the proposed NSPS will have no tangible impact on the patties that it regulates? a. If EPA believes that the proposed NSPS will have tangible impacts on regulated parties, what are those impacts? b. If EPA believes that the proposed NSPS will have no tangible impacts on regulated parties, why is EPA engaged in a costly and resource-intensive proceeding that will have no impact in the real world? And Commenter 9195 notes: The GHG NSPS is being sold to the public based on EPA's linking of CO2 emissions to potential negative impacts of climate change. Yet the proposed rule states that the GHG NSPS "will result in negligible CO2 emission changes ... by 2022." a. How much CO2 does EPA estimate that the III (b) proposal will prevent between its initial proposal and the 8 year window for review? b. Has EPA modeled the climate impacts of these anticipated reductions? Why or why not? If so, please provide the assumptions included in this modeling. c. President Obama's executive order on regulations requires that for any regulation, the benefits must justify the cost. In light of the absence of demonstrated benefits associated with this proposal, how do these new standards meet the President's cost-benefit requirement?
Commenter 10046 states in proposing to apply no CO2 emissions limits to transitional new coal-fired projects (i.e., sources in advanced development in EPA's now-withdrawn 2012 GHG NSPS proposal), EPA cited the small number of these source and the possibility that promulgating a standard of performance would not have a beneficial environmental impact as reasons to apply no CO2 limits at all. 165 (165 Standards of Performance for Greenhouse Gas Emissions for New Stationary Sources: Electric Utility Generating Units. Clearly, according to EPA, there is some level of GHG emissions above zero where an NSPS would have no beneficial environmental impact. Notably, the number of new units in development EPA proposed to exclude in 2012 far exceeded the one maybe unit it projects might be subject to this proposal. Commenter continues that apart from failing to explain how none, or one, or two new low-emitting coal plants with CCS could possibly satisfy the significant contribution (or even the newly-minted rational basis) test, EPA does not acknowledge that it must make this assessment in accordance with its established past agency practice developed in making prior cause-or-contribute-significantly determinations, or validly explain and justify its new approach within the statutory framework. Under that established pattern of practice, which has been upheld by the courts, EPA specifically looks at the level of emissions expected from new sources in the source category and does not make findings when it expects few or no new sources to be built. 
Commenter 10046 also remarks a review of EPA's past practice indicates that EPA will also decline to regulate a source category where no prospect for meaningful emissions reductions exists. That prospect occurs when no new sources are projected to be built. But it also occurs when any such new sources will necessarily be controlled at least to the level of EPA's NSPS, thereby providing no realistic prospect of any emissions reductions from promulgation of this NSPS. Hence, consistent with its past practice, EPA must decline to regulate the coal-fired EGU source category. As EPA acknowledged in defending the legality of its Tailoring Rule, past agency practice is important: While not conclusive, it surely tends to show that the EPA's current practice is a reasonable and hence legitimate exercise of its discretion . . . that the agency has been proceeding in essentially this fashion for over 30 years. Of course, the converse is also true. Where, as here, EPA is deviating from the approach it has used in determining significant contribution and authority to regulate for more than thirty years, that unexplained deviation provides strong evidence that EPA's approach is not a legitimate exercise of the agency's authority. That conclusion is further supported because EPA's historical approach adheres closely to the purpose of subsection 111(b), which is to prevent new pollution problems. That purpose cannot be furthered when EPA expects few or no new units (no new air pollution created), and when any new units will already meet the standard (no new air pollution prevented). EPA can rhetorically disclaim the need to identify a specific threshold for the amount of emissions from a source category that constitutes a significant contribution, but it cannot support its conclusion that under any reasonable threshold or definition, the emissions from EGUs are a significant contribution. Nor has it even analyzed the issue in a rational manner by asking the same questions and making the same assessments it has always asked and made in over thirty years of rulemaking under subsection 111(b). Each of the points and authorities presented above apply equally, whether or not EPA must make a significant contribution finding, or, as the Agency proposes, must only demonstrate a rational basis for controlling the emissions of the pollutant, since the factual flaws in EPA's analysis (i.e., very few to no new sources will be constructed and any new sources constructed will be equipped with CCS anyway) are relevant to either inquiry.
The commenter is not correct that the final standards of performance are without benefits.  The new source standards require a new coal-burning power plant to reduce carbon dioxide emissions to a level reflecting both the most highly efficient boiler design, and partial capture and sequestration of carbon dioxide. The final standard of performance will result in meaningful and significant emission reductions of carbon dioxide emissions from a new coal-fired power plant. The EPA estimates that a new highly efficient 500 MW coal-fired boiler meeting the final standard of performance will emit about 354,000 fewer metric tons of CO2 each year than that new highly efficient unit would have emitted otherwise. That is equivalent to taking about 75,000 vehicles off the road each year and will result in over 14,000,000 fewer metric tons of CO2 in a 40-year operating life.  The plants built under this standard would be cleaner than the average coal unit operating today  -  which emits over 4 million metric tonnes of CO2 a year. By comparison, a new natural gas plant would emit 1.7 million tonnes a year, or about 2.3 million metric tonnes less; and a new, modern coal unit would emit no more than 3 million tonnes per year, or about 1 million tonnes less. See preamble section V.K.  

Should there be a situation where there is interest in new coal, therefore, the standard will prevent construction of new high-emitting coal plants without a requirement to control emissions to the extent possible using the BSER.  Given their long lifetimes, construction of new high-emitting coal plants could lock in their higher emissions for many decades to come.  Moreover, as shown in RIA chapter 5, the monetized benefits of control would also exceed control costs under a range of assumptions.  

The standards of performance adopted today also create a floor  -  a fixed minimal level of stringency  -  for all individual permits for new sources.  This ensures that states and project developers who previously may have ignored climate concerns can no longer do so.  The standards also ensure that project developers who have ignored market signals to build lower CO2 plants cannot do so. 

The standards of performance also serve to promote further development and implementation of carbon capture and sequestration technology. It is a documented phenomenon that national rules requiring large emission reductions have resulted in significant upswing in inventive activity to develop and perfect needed emission control technologies. See preamble section V.L.

The new source performance standard adopted here will not be an impediment to construction of new coal-burning capacity.  Indeed, availability and deployment of carbon capture technology could prove a lifeline to the industry.  As the scourge of climate change becomes increasingly manifest, the ability to use coal without substantial adding to CO2 emissions will be more and more important. Today's action sends a strong signal that low-emitting coal-burning capacity is feasible, and that coal can thereby have an important place in a lower-carbon energy future. See preamble section V.I.4.

It is correct that the base case modeling the EPA performed for this rule projects that, even in the absence of this action, new fossil fuel  -  fired capacity constructed through 2022 and the years following will most likely be NGCC capacity that complies with the final standards.  This is due to current and projected economic market conditions.  See generally RIA chapter 4.  Nonetheless, there could be circumstances where new coal-fired capacity is built  -  commenters to EPA's initial proposal maintained adamantly that this was a possibility (although no specific examples have as yet been provided).  In that event, EPA conducted further analysis which shows that there would be net quantified monetary benefits to society in the form of reduced CO2 emissions and secondary fine PM emissions from SCPC facilities (due to reduced SO2 emissions).  See RIA chapter 5.2.  That is, for each new SCPC facility that would be constructed, the cost of meeting a 1400 lb/MWh-gross standard is more than offset by the monetized benefits of the CO2 and secondary fine PM. This analysis does not quantify other benefits of the standard.  
The standard provides certainty for new plants (see, for example, the AEP FEED study associated with the Mountaineer project, where the company states that it was abandoning the project due in part to regulatory uncertainty, and the contemporaneous statements of Alstom Vice President MacNaughton that "[t]he [CCS] technology works.  But without clear policies in place outlining options for cost recovery, power generators are hard-pressed to invest in its continued refinement", and that "the cost of electricity generated by coal and natural gas plants equipped with CCS is competitive with other low or no-carbon energy sources, such as wind, solar, geothermal, hydro and nuclear")), and a means to enable carbon control technology that will allow future coal  -  fired capacity in a reduced carbon economy.  The commenters are also correct as a matter of law that some type of section 111 (b) standard is a legal condition precedent to section 111 (d) guidelines for existing sources, but this rule has positive benefits with or without consideration of that additional factorPower plants are the biggest domestic source of carbon pollution. While companies building power plants today are already making cleaner generation choices, such as natural gas combined cycle or coal with CCS, the proposed rule would lock in a lower carbon future and make sure this progress continues.  

Thus, the primary conclusion of the Regulatory Impact Analysis was that there will be negligible costs as a result of the regulation. In addition to the primary analysis, the Regulatory Impact Analysis for the rule also included several illustrative analyses, examining the costs of the rule under a range of natural gas prices and the cost associated with building a coal plant with CCS. This analysis found that, while there are additional costs to building a coal-fired power plant with CCS, there are also climate and human health benefits, as well as potential for revenue from enhanced oil recovery.
Commenter 9666 remarks that EPA states that this rule "eliminates uncertainty" that has prevented CCS from getting off the ground, id., but this rule does not promote the construction of CCS. EPA has previously noted that the purpose of the Act's section 111 provisions is to "disseminat[e] the best system of emission reduction (BSER) throughout an identified source category" not to "significantly narrow the nation's choices for types of steam electric generation and fuel to power it." EPA's action with this proposed rule diverges from this policy EPA's identified BSER cannot be deployed throughout the source category, and does significantly narrow the nation's energy choices. 
Commenters 8995, 7977, 10046 state CCS is at best an unproven and expensive experimental technology that should not be used as the basis for emissions standards in the existing source rule. We urge EPA to decline to adopt these assumptions in the existing unit rule in light of the agency's assertion that it is seeking cost-effective and flexible solutions. 
Commenter 10046 states EPA appears to project that exactly zero new coal units will be built in a timeframe that would cover them as new units subject to this proposal. While the RIA projects cumulative capacity additions of coal with CCS at 2 gigawatts (GW) in 2020, this is misleading. EPA's actual Integrated Planning Model (IPM) analysis projects that 2 GW will already exist by 2015. EPA's IPM documentation lists the lead time of all CCS units as four years. EPA's projected 2 GW of coal units necessarily had to have begun construction well before 2015. Hence, per EPA's own assessment, none of that 2 GW will be new capacity subject to this NSPS. 
Commenter 10607 states fewer than 18 months later, in September 2013, however, EPA's advance release of the current NSPS proposal claimed that CCS was BSER for coal-fired EGUs. As discussed below, EPA's proposed rule does not support this conclusion, nor is there sufficient analysis in the proposed rule as to why BSER for non-coal fired EGUs should also rely on application of CCS to at least part of their emissions.
The RIA base case, EIA reference case, and EIA alternative scenarios all project that no new non-compliant coal capacity will be built in the regulatory timeframe.  If new non-compliant capacity were to be constructed, however, the final standard of performance would result in significant CO2 reductions, comparing SCPC CO2 emissions with an SCPC meeting the promulgated standard of performance.  See preamble section V.K.  As the commenter notes, the IPM base case does include a small amount of new coal-fired generation with CCS, in response to federal and state incentives. This is assumed to be compliant with the standards even in the absence of the rule. The practical effect  -  no impacts from these standards  -  is the same whether these had already commenced construction prior to the effective date of the standard or whether they have yet to commence construction. Commenter 9666 indicates that the final standard of performance narrows fuel choices and does not promote use of advanced technology.  The EPA notes American Electric Power's public statements that CCS may prove a salvation to the coal industry's future, see preamble section V.I.4.  Nor does the standard restrict fuel choices.  There are alternative compliance pathways to meeting the final standard of performance which do not necessitate sequestration.
Commenter 9666 states that Table 5-14 in the RIA does appear to compare the benefits of a coal-fired unit with and without CCS technology. At a 5 percent discount rate, however, the benefits are just $2.10 to $3.20 per MWh, and would be even lower or negative if EPA had estimated this at the 7 percent discount rate recommended by OMB for use in regulatory impact analyses. 
In Chapter 5 of the RIA for this final rule, the EPA presents an analysis of the relative benefits of a coal-fired unit complying with these standards compared to a non-compliant coal unit. Based on the emission data provided in NETL 2015, EPA found the benefits were $3.20 to $18/MWh for coal with CCS and $1.50 to $14/MWh for a coal unit co-firing natural gas. These benefits exceed the incremental cost of control under a range of assumptions.

Regarding the use of discount rates for the social cost of carbon, the federal government typically uses the Social Cost of Carbon (SC-CO2) to estimate the social benefits of CO2 reductions from regulatory actions that impact cumulative global emissions. An interagency working group that included the EPA and other executive branch entities used three integrated assessment models (IAMs) to develop SC-CO2 estimates and selected four global values for use in regulatory analyses. The SC-CO2 is not estimated at a 7 percent discount rate. Three values are based on the average SC-CO2 from the three IAMs, at discount rates of 5, 3, and 2.5 percent. SC-CO2s at several discount rates are included because the literature shows that the SC-CO2 is quite sensitive to assumptions about the discount rate, and because no consensus exists on the appropriate rate to use in an intergenerational context (where costs and benefits are incurred by different generations). The fourth value is the 95th percentile of the SC-CO2 from all three models at a 3 percent discount rate. It is included to represent higher-than-expected impacts from temperature change further out in the tails of the SC-CO2 distribution. See response to comments section 4.4-7 for more details regarding the discount rates applied to the SC-CO2, 4.4-8 for details about the application of the estimates, 4.4-1 for the methodology used to develop the estimates, and 4.4-5 for discussion about consistency with OMB guidance. See also the RIA Chapter 3 for a discussion about the SC-CO2 estimates.
Commenter 9666 states that in Chapter 5 of the RIA, EPA estimates the benefits of using NGCC instead of a traditional PC unit. It is not clear, however, why EPA compares NGCC to conventional coal units. The proper comparison should be of the estimated costs and benefits of constructing a conventional coal-fired unit with the estimated costs and benefits of constructing a coal-fired unit that would meet the proposed standards.
The Regulatory Impact Analysis for the regulation includes several illustrative analyses of benefits and costs. The section cited by the commenter examines the difference in emissions and benefits between an NGCC and a conventional coal unit. The intention of this section is to illustrate a situation where a non-compliant coal unit is cost competitive with a natural gas unit and the operator chooses to build an NGCC in order to comply with this standard. As shown in the analysis, it is only at unexpectedly high natural gas prices that this situation would occur and even then, the benefits would exceed the costs under all but unprecedented cost levels. As the commenter notes, it is also useful to compare the costs of a non-compliant coal unit to one that is compliant. For this reason, the RIA also includes an analysis of the difference in emissions and benefits between a conventional coal-fired unit and a coal-fired unit that meets the standard (both with CCS and through co-firing) which shows that the standard's quantified benefits would exceed regulatory costs under a range of assumptions. (See Chapter 5 of the RIA.) See also preamble section V.H.4 comparing capital cost increases associated with the standard on a per-plant basis, and comparing SCPC with and without partial CCS.
Commenter 10952 states that they believe this CCS mandate ultimately would perversely influence worldwide greenhouse gas emissions, leading to more emissions not less, because of its effect on bringing about true CCS demonstration and commercialization. Commenter adds the U.S. can and should be a leader in developing CCS, but that is an extremely unlikely prospect under this proposal. Consequently, instead of striving to develop CCS within the next ten years for future application, no new coal fired EGUs would likely receive funding or be built in this country that would implement experimental CCS concepts. Meanwhile, China is scheduled to build 21,000 MW of new coal fired EGUs annually for the next ten years (210,000 MW total) and U.S. baseload generation is expected to increase a mere 29,000 MW. Under this proposal, no U.S. new baseload generation will be from new coal-fired units. As a result, China's new unit coal-fired CO2 emissions will grow by approximately 6.23 billion tons, while new unit natural gas U.S. emissions will increase by about 559 million tons. Even assuming all U.S. new baseload demand would be met by coal over the next ten years, total U.S. growth in the electric utility sector would be about 914 million tons. Assuming this proposal does what NRECA anticipates, eliminated all new coal, the maximum possible CO2 reductions under this proposal are about 355 million tons or five percent of China's growth over the next ten years. Results under this proposal: no gain in CCS viability, a missed opportunity to foster worldwide CCS application, minimal and inconsequential reductions in U.S. CO2 emissions, and an increase in worldwide CO2 emissions that without this proposal we could have been on tract to curb significantly going forward.
 These comments are beyond the scope of this proceeding.  Section 111 (a) is a technology-based standard, and the new source standard adopted here faithfully implements its provisions.  Moreover, this standard applies to the largest domestic source of CO2 emissions, by a wide margin.  The EPA also made a rational choice not to control GHGs emitted in small amounts from new sources.  See preamble section III.G.  So the rule does reasonably discriminate between large and small volume GHG emissions.  Moreover, China has committed to reducing GHG emission by 2030, based in aprt on U.S. emission reduction actions (light and heavy duty vehicle standards), and proposals (under section 111 (b) and (d)).  China has also shown considerable interest in the CCS technology, visiting the Boundary Dam facility every few weeks, according to SaskPower executives.  See POWER magazine , Aug.1, 2015.
Commenter 10952 states that EPA contends that the proposal has no real impact because other generation options are and will remain at lower cost. EPA cannot know this and at either rate it is outside of its regulatory discretion to define reasonable cost based on what other generation options may or may not be available now or in the future. This winter, natural gas rates rose sharply and when unavailable, electricity supply barely could meet demand Because the proposed NSPS takes effect immediately, carbon capture technology must be adequately available for new coal-fired EGUs immediately and at a reasonable cost. This proposal does not demonstrate that carbon capture sequestration or storage (CCS) is available at all and certainly not at a reasonable cost.
The EPA's modeling, conducted using the Integrated Planning Model (IPM), as well as modeling conducted by the U.S. Energy Information Administration (EIA) showed that new generating capacity built through the period of analysis would be in compliance with the standard even in the baseline scenario. This finding held true even under a number of alternative scenarios.
New plant construction 
Commenter 3176 states the EPA defends the proposed rule, in part, by claiming that utilities' long-term resource plans do not call for the construction of any new coal-fired generation in the coming decade and therefore, any cost concerns surrounding the proposed rule will not be realized. Commenter 3176 continues in previous comments, the APSC noted that scientists and climatologists continue to disagree as to whether human activities, and more specifically greenhouse gas emissions, are the primary driver of any measurable climate change (versus, for example, solar cycles) and whether environmental regulations in the United States alone can have any effect on global climate change.
Commenters 8949, 8974 state EPA should establish separate and unique fuel-source categories, and corresponding appropriate GHG NSPS, for each fossil fuel source.
Commenters 8971, 8971, 10034 state that no/few new coal-fired power plants will be developed, then USEPA lacks the basis and justification for setting NSPS standards for coal burning sources (i.e. boilers and IGCC).
Commenter 10869 states EIA's most recent projections show that even under a business-as-usual scenario, very few new conventional coal-fired plants are forecast to be built through 2040. Thus the proposed carbon standard for new plants simply underscores a reality that is already underway and will not impose additional costs on industry beyond what would occur in a business-as-usual scenario. Of course, this also means that the standard for new plants will likely not make a meaningful contribution to reducing U.S. global warming emissions if market conditions remain as currently forecast (with very few new coal-fired power plants coming on line). Commenter states there is a need to move quickly toward actions that will actually reduce those emissions, including setting a standard for existing power plants. The draft standard for new power plants does serve as a necessary regulatory predicate to the standards for existing power plants and in that sense are very valuable. They will also serve as a "backstop" in case market conditions were to change.
The commenter is not correct that the final standards of performance are without benefits.  It is correct that the base case modeling the EPA performed for this rule projects that, even in the absence of this action, new fossil fuel  -  fired capacity constructed through 2022 and the years following will most likely be NGCC capacity that complies with the final standards.  This is due to current and projected economic market conditions.  See generally RIA chapter 4.  Nonetheless, there could be circumstances where new coal-fired capacity is built  -  commenters to EPA's initial proposal in 2012 maintained adamantly that this was a possibility (although no specific examples have as yet been provided).  In that event, EPA conducted further analysis which shows that there would be net quantified monetary benefits to society associated with reduced CO2 emissions and secondary fine PM emissions from SCPC facilities (due to reduced SO2 emissions).  See RIA chapter 5.2.  That is, for each new SCPC facility that would be constructed, the cost of meeting a 1400 lb/MWh-gross standard is more than offset by the monetized benefits of the CO2 and secondary fine PM under a range of assumptions. This analysis does not quantify other benefits of the standard.  The standard also provides certainty for new plants (see, for example, the AEP FEED study associated with the Mountaineer project, where the company states that it was abandoning the project due in part to regulatory uncertainty), and a means to enable carbon control technology that will allow future coal  -  fired capacity in a reduced carbon economy.  The commenters are also correct as a matter of law that some type of section 111 (b) standard is a legal condition precedent to section 111 (d) guidelines for existing sources, but this rule has positive benefits with or without consideration of that additional factor. Power plants are the largest domestic source of carbon pollution. While companies building power plants today are already making cleaner generation choices, such as natural gas combined cycle or coal with CCS, the proposed rule would lock in a lower carbon future and make sure this progress continues.  The plants built under this standard would be cleaner than the average coal unit operating today  -  which emits over 4 million metric tonnes of CO2 a year. By comparison, a new natural gas plant would emit 1.7 million tonnes a year, or about 2.3 million metric tonnes less; and a new, modern coal unit would emit no more than 3 million tonnes per year, or about 1 million tonnes less. 

In addition, EPA strongly disagrees with comments asserting disagreement about whether human activities and greenhouse gas emissions are the primary driver of recent climate change.  See the 2009 Endangerment Finding as well as response to comments 4.1-8 and RIA Chapter 3 for additional discussion.
Outside of the agency's regulatory discretion to define reasonable cost 
Commenter 10086 states EPA contends that the proposal has no real impact because other generation options are and will remain at lower cost, but EPA cannot possibly know this and at either rate it is outside of the agency's regulatory discretion to define reasonable cost based on what other generation options may or may not be available now or in the future.
The commenter is correct that no entity can predict the future with absolute probability.  The commenter is incorrect in thereby stating that reasonable predictions cannot be made and actions taken predicated on those reasonable predictions.  The EPA has done so here.
Need to measure CO2 benefits separate from PM, SO2, and NOx
Commenter 10023 states EPA does not separately measure the benefits associated with the control of CO2 emissions that would purportedly result from this proposed rule. Instead, EPA estimates the combined benefits of reducing CO2, fine particulate matter, SO2, and NOx emissions. If the purpose of the rule is to address CO2 emissions from EGUs, EPA cannot properly mix in to its estimates the purported benefits of controls of other emissions. Commenter states that EPA needs to measure separately the benefits of purported CO2 emission reductions.
 The EPA disagrees with the commenter's statement that the Agency did not separately measure the benefits associated with various emission reductions. OMB guidance requires agencies to consider all of the impacts of regulations, including benefits of co-emitted pollutants. In the Regulatory Impact Analysis, the EPA separately estimates the human health and climate benefits of this regulation and then adds these together to estimate the total benefits of the regulation.  Moreover, the EPA notes that the determination that the costs of the rule are reasonable are based on the analysis in sections V.H. and I. of the preamble to the final rule.  However, the EPA has also found that if new coal capacity is added, there will be net quantified benefits under a range of assumptions, in the form of both CO2 reductions and reductions in emissions of criteria pollutants that will occur due to implementation of the standard.  See RIA chapter 5.  This may be another reason to find the standard to be adequately demonstrated considering costs.  The commenter's evident view that the standard of performance can only be justified, and that a system of emission reduction is "best" is limited exclusively to the pollutant being directly does not make sense.  Suppose technology A removed 100 units of CO2 and no other pollutants (or had a negative impact on other pollutants), and technology B removed 99 units of CO2 and significant amounts of other air pollutants as well. The commenter suggests EPA would have to ignore the impact of technology B on air pollutants other than CO2 in deciding which one is the "best" system of emission reduction.  This approach would not be consistent with the requirement that EPA must consider collateral impacts in determining which technology is "best" under section 111.  See Essex Chemical Corp., 486 F. 2d at 439; Portland Cement. 486 F. 2d at 386. Moreover, the EPA notes that SO2 is a criteria pollutant (and indeed, is already regulated under NSPS for this industry), so no issue is raised regarding considering benefits of control of a pollutant not otherwise within the scope of section 111 standards.
Commenter 8954 states that in addition to the ongoing impacts of regulation already promulgated by EPA, proceeding down a regulatory path which effectively prohibits the development of new coal generation risks U.S. energy reliability, affordability, security and diversity for no identified benefits. It puts at risk more than 800,000 coal related jobs as well as our business and manufacturing base. It inflicts the risk of rising electricity prices on all people and businesses, but most importantly on those who can least afford it such as the poor and those on fixed incomes. Commenter requests that EPA significantly revise it to address the concerns and shortcomings outlined above. 
Commenter 2471 states they are concerned that USEPA's plan to reduce carbon from fossil-fuel fired EGUs will drive United States' (US) energy policy away from coal, even though some research shows total lifecycle carbon emissions from gas are nearly as high as or higher than coal.
Commenters 9734, 9382 states coal-fired power plants in the U.S. contribute only approximately 4% to global GHG emissions. The U.S. power fleet has already reduced CO2 emissions by 16% below 2005 levels, with CO2 from coal-fired power plants reduced by almost 25%. These reductions are a result of the utility sector's shift to natural gas generation. EPA should allow coal-fired power plants to continue to make these reductions in a reasonable manner and in response to market pressures, instead of by regulatory fiat. Furthermore, the regulations at issue will not have a meaningful impact on global climate change. The minimal impact that these regulations will have on the environment further underscores the need for all GHG regulations to be economically achievable.
The EPA's modeling, conducted using the Integrated Planning Model (IPM), as well as modeling conducted by the U.S. Energy Information Administration (EIA) showed that new generating capacity built through the period of analysis would be in compliance with the standard even in the baseline scenario. As a result, this regulation is not expected to impact the mix of generation sources in the period of analysis. Additionally, the regulation does not ban the construction of coal-fired generation, but instead requires that newly-constructed coal EGUs use modern technology. The Regulatory Impact Analysis for the rule includes several illustrative analyses, examining the costs of the rule under a range of natural gas prices and the cost associated with building a coal plant with CCS. (See Chapter 5 of the RIA.) This analysis found that, while there are additional costs to building a coal-fired power plant with CCS, there are also climate and human health benefits which exceed those costs under a range of assumptions, as well as potential for revenue from enhanced oil recovery.
GHG emissions will increase regardless
Commenter 10951 states as shown in the National Mining Association's comments, EPA is mistaken that no new coal-fueled generation stations will be built in the United States. But there is a more fundamental reason why EPA's anti-coal policies will not meaningfully address the global level of atmospheric GHGs that EPA says will be the cause of deleterious climate change. Other countries are dramatically increasing their use of coal, and this increased coal usage and indeed the fact that the developing world will continue to develop and will continue to increase its usage of coal no matter what policies the U.S. pursues internally is resulting in increasing GHG emissions globally that far outstrip any U.S. reductions that EPA believes it will cause.
As discussed in Response to Comments Section 3.2 and in the RIA Chapter 4, EPA's modeling, conducted using the Integrated Planning Model (IPM), as well as modeling conducted by the U.S. Energy Information Administration (EIA) showed that new generating capacity built through the period of analysis would be in compliance with the standard even in the baseline scenario and, as a result, the rule would not lead to changes in behavior. This finding held true even under a number of alternative scenarios. As a result, the EPA projected there would be negligible costs, benefits, energy impacts (including changes to electricity prices), employment impacts, or economic impacts associated with the rule in the period of analysis. (See Chapter 4 of the RIA.) Based on these conclusions, we would not expect business relocation, impacts to manufacturing, or the transfer of industrial activity to other countries.

Furthermore, all countries contribute to climate change, and no one nation can stop it alone.  All nations that are significant emitters of greenhouse gases will need to take the steps necessary to reduce their emissions in the near and long term. We have an obligation to ensure that the world we leave behind for our children and our grandchildren is healthier and safer. This rulemaking further establishes the United States as a leader in international efforts to secure an ambitious and lasting climate agreement in 2015 that will include significant contributions from all major economies. Already, U.S. action has helped spur announcements from China and Brazil to limit their own greenhouse gas emissions, building momentum for broader global commitments later this year in Paris.  Moreover, as a sign that requirements to use CCS will spur further use, including internationally,   representatives from more than 30 countries have visited Boundary Dam #3, and SaskPower official Mike Monea was quoted in the Financial Times article as saying that a Chinese delegation visits BD3 "every two or three weeks." Mr. Monea stated "China is just gathering information right now. When it moves, it will be significant. I think that's where the next projects of size and number will be happening." POWER magazine, August 1, 2015 (available in the docket for this rulemaking).

This is not to say that foreign policy considerations are driving EPA's determination as to what BSER adequately demonstrated is here.  That determination rests exclusively on the decision factors in section 111 (a).  Nonetheless, the commenters' statements that U.S. rules addressing GHG emissions have no benefits due to the global scope of the issue are unfounded.
EPA's discretionary authority - petroleum refining precedent
Commenter 10662 states nothing compels EPA to propose these regulations at all and, if anything, the lack of a persuasive legal basis and adequate factual support for this proposed rule compel EPA not to promulgate the rule. In a recent decision not to adopt GHG NSPS for petroleum refineries, EPA concluded definitively that it has wide discretion in deciding whether to establish standards for a new pollutant when conducting the periodic review of existing NSPS. 
The agency also has wide discretion to choose when to regulate.  The industry sector at issue here is the largest domestic source of CO2 (and CO2e) emissions, by a huge margin.  It is reasonable, therefore, to deal with the issue of control of GHG emissions which contribute to the endangerment resulting from emissions of the air pollutant GHGs by addressing the emissions from the largest contributors.  The EPA has done so by controlling vehicular GHG emissions from light duty vehicles and heavy duty vehicles and engines, and by issuing the standard of performance in this rulemaking.  There is no question that the EPA has legal authority to issue NSPS to control CO2 emissions from new fossil-fuel fired electricity generating units.  The Supreme Court indeed held so specifically in American Electric Power, relying on that authority to reject a claim under federal common law.  

Natural Gas Price Assumptions
Multiple questions
Commenter 9686 calls for an open analysis of the effects on natural gas price of: the post 2015 demand for LNG exports, the influence of a natural gas cartel comprised of Russia, Qatar and Iran, the impact on natural gas supply from shale formations, especially the Marcellus, because of the growing bans on hydraulic fracturing, and the impact on the cost structure of natural gas production because of potential new regulations on methane emissions from the gas wellhead to the power plant.
EPA disagrees with this comment.  The IPM modeling for this rule took account of expected demand for LNG, and DOE has found that impacts of LNG on gas demand and prices are minimal.  Our IPM modeling also takes into account existing bans on development of shale resources. Impact analysis considers regulations currently on the books. Other factors identified in this comment are too speculative to realistically consider in the impact analysis.
Commenter 10092, 8974, 10951, 7433, 9407, 9772, 9590, 10024 state historically, it is important to note that fuel prices can be volatile and the US has seen dramatic shifts in the preferred fuel for energy based on the price of different types of fuels. Thus, it is difficult to forecast what type of fuel will be preferred for energy purposes. Commenter 9396, 10665 stated EPA also has not taken into account the potential impact of natural gas exports on pricing, particularly given far higher world natural gas prices compared with continental prices. Commenter 10097, 10665 stated that the price and availability of natural gas are too speculative to make it the only practical choice for new baseload generation.  Commenter added that EPA relies on natural gas pricing forecasts provided by the Energy Information Agency (EIA) of the Department of Energy (DOE), and the EIA has consistently failed to accurately predict natural gas prices, including during the period of significant price volatility from 2000-2008, even as the price spikes were occurring. More recently, regional costs of natural gas have fluctuated in increasingly volatile swings as a nexus of pipeline capacity constraints, volatile weather events, increased residential and commercial demand and electric sector demand has pushed prices higher. Commenter explains that electric utilities take a long term view of investments and plan for cost fluctuations in natural gas pricing. Citing EIA charts, commenter states that assuming that natural gas prices will be low and remain low is not a certainty.  Commenter continues that utilities build plants for diversification reasons not only to mitigate price fluctuations but also to assure reliability. Deliverability of energy at a reasonable price is a critical component of utility planning. Utility generating units are capital-intensive projects that are undertaken with expectations that the plants will have useful lives of 40-50 years. Utilities do not plan such long-term investments on short-term price projections for one fuel. Basing the standard on the short term natural gas price does not meet the evaluation criteria for determining BSER. Forcing dependence on one fuel in large parts of the country is a prescription for not only higher and more volatile natural gas and electric prices but threatens electricity supply shortages and potential rolling blackouts. Commenter endorses the extensive comments submitted by the American Public Power Association (APPA) on the multiple failures of EPA to fully examine these critical aspects of natural gas availability and prices. 

Commenter 10618 states while EIA has examined the role that higher electricity sales and lower yields from shale gas could have on new capacity decisions, other factors could have even more dramatic impacts on natural gas pricing and new build economics such as a move to gas liquefaction. Export within either the U.S. or Canada has the potential to drive up domestic natural gas prices to levels seen internationally, which can be three to four times higher than current domestic prices. Commenter states that EPA's IPM model does not take into account the development of these facilities, even though announced facilities and current market conditions suggest they will be developed. Additionally, a drop in world oil prices could slow down oil and natural gas liquids production activities, reducing the supply of associated gas and increasing the price of natural gas. 

Commenter 6870 provides two figures that indicate some of the riskiness of depending upon natural gas prices for policy: 1)  reference forecasts (the baseline forecasts) for the Annual Energy Outlooks for 2010 through 2013 along with the actual natural gas price for the year (noting that over  time, the forecasts fan out from the actual data. 2) a comparison of  the forecasts for 2010 through 2014 for the period 2013 to 2035, displaying significant variability in the forecasts which points to the riskiness of depending upon natural gas pricing and production as a basis for a policy change that will have a dramatic effect on a key sector of the economy- electric utilities. Comments states that EPA's forecast assumes the price of coal increases even though the demand for coal declines. The argument is that as more coal is mined, the cost of mining the coal will increase. Because of the increased use of Western United States coal, this has not been the case so far. Citing EIA and its AEO 2014, commenter states it is hard to see why future coal prices are expected to increase as much as EPA and EIA have forecasted.

Commenter 9401 states EPA's assumption of no new coal units is a very short-term assessment of the cost of constructing coal-fired generation versus natural gas. Commenter points out that electric generators or industrial consumers make capital investments decisions based on a minimum of 30 years or more time horizons, and natural gas prices will rise over that time frame and coal will be a competitive energy source for power generation. Commenter 9401 notes that demand for natural gas is surging and prices are forecasted to significantly increase. Commenter notes that the American Coalition for Clean Coal Electricity's (ACCCE) cost analysis indicates that new coal plants without CCS can be economic in many regions of the country if the price of natural gas is in the range of $7 per mmBtu or higher.

Commenter 10929 states it is presumptuous that natural gas based generation will be the predominate technology deployed over the next several years based on  natural gas fuel pricing and EPA should avoid attempting to impose a single performance standard on all new units that was drawn from assumptions applicable for a single technology, such as natural gas combined cycle units.

Commenter 8971 states the price of natural gas could continue to move significantly upward despite expectations to the contrary, just as it has fluctuated downward despite expectations to the contrary in the past. Because of this, USEPA's price impact estimate is flawed and does not to adequately account the impact the CO2 NSPS rulemaking may have on electricity prices.

Multiple comments were received describing the volatility of natural gas prices and expressing concerns about the price EPA assumed in its analysis (9033, 10050, 9034, 2471, 2471, 9426, 9592, 10023, 9770, 9201, 10017, 10048, 10048, 10952, 10952, 9666, 9666, 9593). Commenter 9033 states it should be noted that while natural gas is currently low in price and abundant (and projected by EIA to remain so), dependence on gas this winter has driven consumers price spikes with electricity reaching $7,000 per MWh due to infrastructure constraints on gas fuel supplies and that this figure is sharply different than EPA's expected $70 per MWHr. Commenter 10050 states that natural gas prices have more than doubled since their low of $1.82/ MMBtu in April of 2012, and this past winter, natural gas prices in some regions reached record highs with mid-points around $40/MMBtu and bids as high as $100/MMBtu, making EPA's analysis and assumptions for electricity and natural gas pricing are inadequate and unrealistic. Commenter 9593 states that prices reached over $10/mmBtu for a short time only a few years ago.  Winter of 2014 natural gas price spikes were cited by multiple commenters (9034, 9770, 10048, 10048, 10952). Commenters 10048, 10048 state that from January 8, 2014, to March 4, 2014, the price of natural gas increased by 78% nationally.   Commenter 9426 states it is incumbent upon the EPA to investigate the costs, impacts, and implications of the rule in the plausible future world where gas will not be nearly as inexpensive as the EPA currently predicts.  Commenter 9592 provided a natural gas price history graphic below, displaying gas price variability over 20 years, which is about half of the normal 40 year plus operating life of a typical EGU. Commenter adds that new electric generating units must consider fuel availability and cost projections for the 40-50-yr life of the unit.  

Commenter 9201 provides additional cost information of natural gas prices throughout the country and how analysts project the cost trends.  Commenter 10017 states that the cost of the natural gas is sensitive to short-term phenomena and provides the example that, in the near future, many coal-fired units will be retired as a direct result of the CSAPR and MATS rules. Commenter notes that Ohio alone has 27 emitting units that are scheduled for retirement on or before 2015. At least some portion of the generating capacity of these units will need to be replaced by NGCC units, and the commenter predicts the demand for natural gas will increase rapidly in a very short time period as these new units go online. Likely, the costs of natural gas will increase with increased demand. The commenter believes rules such as the proposed NSPS, should not be based on predicted future costs of any commodity, especially those of fuels which have historically volatile markets. Commenter 10952 states that the price volatility and widespread availability of natural gas are too speculative to make it the only practical choice for new baseload generation. Commenter 9666 states that although the Agency acknowledges that gas prices have been highly volatile in recent decades (RIA at 4-31), EPA does not consider the possibility of significant increases in prices. 

Commenter 3176 states by constraining the fuel options available to electric suppliers, the proposed rule imposes an unnecessary cost risk by forcing electric suppliers to rely predominantly on natural gas as the fuel choice for new generation resources, adding that this risk is particularly acute given the historic price volatility of natural gas.

Commenter 9725 states natural gas prices have more than doubled since their low of $1.82 mm/BTU in April of 2012. This past winter, natural gas prices in some regions reached record highs with mid-points around $40 mm/BTU and bids as high as $100 mm/BTU. Daily average power pricing followed swinging wildly from $40 to $800 MWh. In this regard, commenter believes EPA's analysis and assumptions for electricity and natural gas pricing are inadequate and unrealistic. 

Commenter 9657 states this regulation favors electricity generated from natural gas, a fuel with a well-known volatile price and supply history. Commenter remarks that recent production increases related to the proliferation of fracking technology have emboldened a dramatic increase in the share of natural gas in the electricity market. Without any additional regulatory impetus, the Energy Information Administration anticipates that natural gas will grow to over 35 percent of the electricity supply by 2040; just last year, the same projection estimated that natural gas would supply 30 percent of the electricity supply by 2040.  Commenter cautions about the dangers of over reliance on natural gas for electricity generation, citing natural gas spot prices in New England this past winter. Prices reached a record high of nearly $34 per million British thermal units in February 2014, pushing up delivered electricity and home heating prices. This spike led the Federal Energy Regulatory Commission to waive an established cap of $1,000 per megawatt hour for generators.  Commenter contends that an overly stringent regulation for coal-fired power would build a permanent preference to consistently favor natural gas fired power, and this risks dramatically increasing costs and endangers the reliability of our electricity grid when the price of natural gas inevitably experiences perturbations.  Commenter closes, suggesting that EPA exercise restraint in finalizing this regulation. 

Commenter 10097 states they are greatly concerned that future power markets will be so heavily dependent upon natural gas that periodic price volatility will impose significant economic hardships on a demographic already under financial stress.

Commenter 9486 states the change in demand for natural gas in recent years has resulted in a significant price increase over the most recent two months, and this troubling trend could continue forward. Commenter explains that if increased regulatory oversight and slower expansion of the natural gas market occurs, coal will likely become more economical again. However, with implementation of this rule, the cost of natural gas, as well as other fuel sources, would have to rise significantly to add coal as a possible fuel source. If this would occur, it would drive up electricity rates and decrease reliability due to the enormous costs associated with building any future coal-fired power plants.

Commenter 9486 states as the cost of electricity increases, public consumers and businesses small enough to currently be unregulated by the provisions of the Clean Air Act, will stop using electricity to heat water, homes, and businesses. In the Midwest, these people typically substitute the cheapest available fuel (typically coal or wood) and use it in facilities with no or limited emission controls. Commenter asks that EPA develop NSPS standards for residential and commercial sized coal and wood burning furnaces, heaters and water heaters to help maintain local air quality when people switch fuels. Otherwise, a net benefit cannot be assumed for this regulatory action.

Commenters 9197 and 9600 state they remain concerned that over-reliance on natural gas as a fuel source for our electric system could be harmful for the U.S. economy and energy security in the long term due to historically volatile prices. 

Commenter 9497 requests that EPA commit to review the rule within four years of promulgation. The Commission is wary of the dangers of becoming reliant on natural gas given the potential for future price volatility. 

Commenter 1959 states currently, a new NGCC plant is less expensive on a life cycle cost of electricity basis than a new coal plant. The current breakeven point for new coal vs. new gas is when natural gas costs rise above about $6 per MMBTU. If CO2 capture is required for new coal units, then the breakeven point will be when the natural gas cost exceeds $12 per MMBTU - hardly a hedge against volatile gas price swings. 

Commenter 9423 states in the 2000 Annual Energy Outlook report, the Energy Information Administration (EIA) failed to predict the significant spikes and swings in the price of natural gas that occurred between 2000 and 2009. EPA's own regulations on natural gas production, such as the oil and natural gas NSPS and revisions to the National Emission Standards for Hazardous Air Pollutants (NESHAP) rules for oil and natural gas sectors, which were finalized at approximately the same time, April 2012, will increase costs for natural gas producers and thereby increase the cost of natural gas. Similarly, this proposed NSPS rule on CO2 emissions from electric utilities may affect the cost of natural gas by forcing a reduction in demand in other fuels such as coal. The possibility of increased exports of liquefied natural gas may also exert pressure on domestic natural gas supplies, and thus affect the cost and availability of natural gas for power generation. Finally, the price of natural gas is only one factor that power companies consider when evaluating options for new generation. 

Commenter 9772 states Montana Governor Steve Bullock identified the importance of coal and coal-fired electricity generation to our state in a December 18, 2013 letter to EPA Administrator Gina McCarthy, and advised caution about issuing regulations dependent on low natural gas prices that won't last forever. 
Commenter 9666 remarks EPA concludes "[i]t is only when natural gas prices exceed $10/MMBtu on a levelized basis (in 2011 dollars) that new coal-fired generation without CCS approaches parity with NGCC in terms of LCOE." Commenter continues that the Agency further determines that "[a]t natural gas prices above $10.94/MMBtu, the private levelized cost of electricity for a representative new [supercritical PC] unit falls below that of a new NGCC unit." The commenter states that EPA did not run any sensitivity analyses with natural gas prices approaching this price level, and that the highest projected gas price EPA examined was $6.64/MMBtu. 
EPA disagrees.  Volatility is generally defined as short term, but planning for new capacity is based on expected returns for a longer period.     Although there is greater historical variation in fuel prices for natural gas than for coal, both fuels are subject to variation in the long term (See, "Trends in structure of Electric Power Sector Limiting Amount of New Coal" Section B.4 and Figures 7 and 8 in the docket for this rule.).  Moreover, long term contracting and price hedging over shorter periods provide well developed mechanisms to manage risk in natural gas markets.  Also, as new combined cycle gas units operate more in a baseload capacity, they are better able to support the long term contracting process because they can expect to have a steady stream of revenue to support the regular payments under such contracts.  This increased ability to support the longer term revenue stream also means that operators of NGCC facilities will provide greater support for the use of firm natural gas contracts.  These firm contracts will, in turn, support increased pipeline capacity to ensure the a reliable supply of gas where needed to forestall a recurrence of the "Polar Vortex" like winter emergency periods where natural gas and electricity peak demands intersect.  The combination of firm contracts and risk management through market mechanisms will provide the needed basis for managing natural gas pricing and delivery.  For these reasons, EPA believes the rule will aid in easing industry concerns of both natural gas price fluctuations and supply concerns.
Commenter 9514 addresses whether fuel diversity is needed with increasing demand (and price volatility) for natural gas. Commenter 9514 supports EPA's statement that while EIA and IEA project that modest increases in the price of natural gas may occur in the coming years as a result of increasing demand for this fuel, coal-fired power generation will continue to face stiff competition from existing natural gas plants for the provision of baseload power, and will also continue to be uncompetitive as a new source of generation. Commenter 9514 also states that market projections and utility sector analyses also suggest that the baseload shift from coal to natural gas generation in the existing EGU fleet will continue, regardless of whether there are small to moderate natural gas price changes and cites a recent study of the cost impacts of the Mercury and Air Toxics Standards (MATS), the Clean Air Interstate Rule (CAIR), and other regulations found that the implementation of these rules will make the operating costs of natural gas plants cost-competitive with most coal plants - at least up to a natural gas price-to-coal price ratio of 4.3, and even before the implementation of EPA's forthcoming standards for CO2 emissions from existing fossil-fired EGUs, stating that the ratio stood at just 1.8 in 2013, and EIA projects that it will remain at 2.4 or less through 2035. The same commenter concludes that the collective impact of market forces and current and future CAA regulations designed to protect public health are expected to reinforce the competitiveness of CCGT vis-a-vis coal as a source of baseload power. The commenter also concludes that new conventional coal-fired generation will be neither needed nor economically viable over the foreseeable future, regardless of the proposed NSPS and that the existing coal-fired generating fleet is expected to continue to face significant competitive pressure from gas-fired EGUs which are currently a competitive source of baseload power and will likely remain so over the coming decades, as well as from increasingly cost-competitive renewable resources and energy efficiency opportunities.
Thank you for your comments.
Commenters 8501, 10095, 9666 addressed the role of shale gas supply and hydraulic fracturing. Commenter 9426 states that while hydraulic fracturing, the method used to extract shale gas, is not currently subject to significant regulatory burdens, it is reasonably foreseeable that if and when shale gas is regulated, it could have a meaningful impact on the price of natural gas, adding there is no indication that the EPA considered the potential effect of significant shale gas regulation on natural gas prices.   Commenter 8501 states that EPA's statement that the supply of natural gas will increase from new exploration and extraction of shale gas ignores expert opinions about the costs and supplies of natural gas from shale, stating that gas prices are more likely to rise than remain at current levels. Commenter  10095 states  there are uncertainties surrounding: (1) the amount of recoverable reserves in unconventional reservoirs, (2) natural gas extraction techniques, (3) the pace and degree of natural gas exports, and (4) increased demand for natural gas from other sectors of the economy. Yet, commenter adds increased regulation of the natural gas sector, including the primary tool for extraction, hydraulic fracturing, is already occurring, and there is no doubt that it will have some impact on the cost and availability of natural gas in the future. Commenter adds it is unclear if EPA has considered the impact of evolving state- and local-level regulation such as fracking bans and moratoria on natural gas prices in the proposed rule. Commenter 9666 states none of the scenarios EPA assessed includes a future where shale gas extraction is regulated, stating the EPA does not account for this likelihood of regulation and for the gas price uncertainty that will accompany this regulation. Commenter adds it is not clear that EPA accounted for substantial future increases in electricity sector demand for gas, significant increases in demand for gas as a raw material in the manufacturing sector, or a possible substantial increase in natural gas exports.
Commenter 9486 states by limiting focus to direct emissions of CO2 at the electrical generating unit, the proposed rule fails to consider the lifecycle greenhouse gas emissions associated with alternative technology.
Commenter 9497 states shale gas production has driven natural gas prices in recent years, and shale gas has influenced the EIA's price, but there are substantial uncertainties about future shale gas production and prices.  
The EPA has used EIA projected natural gas prices in analyses supporting development of the finals standards and believes them to be the best information available. See other responses to other comment regarding the EIA cost projections and uncertainties associated with future natural gas prices.
Commenters 9678 stated that EPA used up-to-date data on domestic natural gas supply data, noting in the RIA for this re-proposal, EPA reasserts EIA's projections for natural gas availability and updates its assumptions to reflect EIA's Annual Energy Outlook (AEO) 2013. Commenter 9678 agrees with EPA's use of up-to-date assessments in both the 2012 and 2013 GHG NSPS proposals and asks that EPA continue to use up-to-date assessments of natural gas supply and availability in future regulatory actions, including any rules addressing interstate transport of air pollution. 
In the final RIA, EPA used data from AEO 2013 and 2014 and used NETL cost data from 2015.
Commenters 9678, 10952 stated that natural gas pipelines are not available in all regions of the U.S. and natural gas may not be available as a fuel for many EGUs. Commenter adds 10952 in many rural areas where electric cooperative baseload facilities are located natural, gas supplies are either significantly limited or nor available at all shows electric cooperative rural service areas where natural gas supply via pipeline is hundreds of miles away from where additional electric generation may be required. 
Commenters 9396 and 10665 stated EPA did not take into account the costs of building out the required additional natural gas infrastructure necessary to supply the natural gas needed for new generation. 
 EPA disagrees with these conclusions.  This rule will not impact the ability of existing sources to continue to meet generating requirements.  First, EPA notes that a electricity customer does not need to be connected to a natural gas pipeline to receive power from natural gas generation.  In addition, natural gas infrastructure issues are entirely manageable under this rule, where needed.  Natural gas pipeline capacity has historically expanded to meet the needs of new natural gas generation capacity, and the same developments will happen in the future, and the RIA demonstrates that future demand increases are within historical ranges.  This is particularly true where additional capacity will be required to meet the requirements of generation is already connected to the pipeline system, or areas where natural gas is already connected.  It is also true for areas not yet connected to the natural gas pipeline system.  Thus, the normal expansion process will address most cases where additional infrastructure is needed for continued reliable operation and new sources of fuel are added.  In the near term, there should be few additional infrastructure needs, as this rule does not affect the continued operation of any existing sources.  In the longer term, as the generating fleet turns over, much of the existing fossil generating will remain and continue to be diverse, while the normal infrastructure development noted above can accommodate much of the new demand, and electricity transmission can be expanded to deliver natural gas powered electricity to new customers.  Moreover, much of the new demand need not be met by natural gas, but by various forms of new renewable energy.  

Economic Impact Assessment Required by Section 317
Commenter 9678 states that natural gas has increased the fuel diversity of the electric grid. Per the EIA the grid has become more diverse with growth of renewable generation resulting from public policy mandates and incentives and natural gas generation resulting from stable affordable natural gas prices in the wake of the shale gas revolution. They add the flexibility that natural gas provides makes natural gas the fuel of choice under energy and environmental policies that aim to ensure emission reductions while minimizing adverse economic impact. 
Thank you for your comment.
Several commenters (9666, 10098, 10239) stated that the proposed rule does not contain the economic impact assessment required by CAA section 317. 
Commenter 9666 states the RIA does not satisfy the section 317 requirements that EPA analyze: (i) how the estimated costs of compliance would vary depending on the effective date of the standard; (ii) how the estimated costs of compliance would vary with the development of less expensive, more efficient measures of compliance with the standard; (iii) the potential inflationary or recessionary impacts of the rule; (iv) the effects of the rule on consumer costs; and (v) the effects of the rule on energy use (See id. section 317(c)(1), (2), (4), (5)), and  as a result, the Agency has not fully examined the important implications of its proposed standards for the nation's economy. The commenter adds that because the economy relies on the energy sector for a reliable, affordable supply of electricity, any effect of this rule on the utility industry will be tied to impacts on the economy, and, for that reason, it is important that EPA's proposed rule contain the required economic impact assessment.  Further, the commenter states that an economic impact assessment should include an explanation of how that assessment informed its proposed action, and EPA cannot address the economic factors contemplated in section 317 in its final rulemaking. Instead, EPA must withdraw this proposed rule and, if it wishes to proceed, publish a new notice of proposed rulemaking containing the mandatory economic analysis. Not doing so could subject EPA to citizen suits seeking to enforce the Agency's nondiscretionary duty to conduct an economic impact assessment, and EPA could be subject to penalties for contempt of court if it violates a subsequent order compelling it to do so. (CAA Section 317(f)).  Another commenter (10098) states that EPA cannot ignore the requirement to conduct a complete cost benefit analysis by asserting that the rule will have no costs or benefits. Moreover, they add that EPA incorrectly asserts that no new coal-fired capacity will be constructed in the absence of this rulemaking. The final commenter (10239) states that EPA's analysis is deficient and underestimates the likely consequences of the EPA's proposal and violates the Clean Air Act. They state that Section 317 of the Act requires an economic impact analysis for "any new source standard of performance under section [111] of this title." The EPA does not mention Section 317 in the proposed rule or RIA. The economic impact analysis must be "as extensive as practicable," and the EPA's treatment of economic impacts does not account for the short- and long-term impacts. Likewise, under Executive Order 13563, the EPA must "take into account the benefits and costs, both quantitative and qualitative," and "propose or adopt a regulation only upon a reasoned determination that its benefits justify its costs..." The proposed rule will have a direct effect on the development of new coal-fired EGUs. An economic impact analysis compliant with CAA Section 317 and Executive Order 13563 would rebut the EPA's "no cost" conclusion and demonstrate the arbitrariness of the EPA's analysis.
Commenter 10098 states the cost-benefit analysis violates existing requirements, offering for example Section 317 of the Clean Air Act, entitled "Economic Impact Analysis." Commenter states the very first-listed category of rulemaking to which this section applies is "any new source standard of performance under section [111] of this title." CAA section 317(a)(1) yet nowhere in the  proposed rule does EPA reference this section of the Act. Nor is it mentioned in the RIA. Section 317 requires EPA to prepare an economic impact assessment that takes the following into account: the cost of compliance with the new standard, including based on the effective date of the standard; the potential inflationary or recessionary effects of the standard; the effects of the standard on competition with respect to small businesses; the effect of the standard on consumer costs; and the effect of the standard on energy use. The analysis is required to be "as extensive as practicable." While EPA has superficially treated some of these topics in the proposed rule and RIA, its analysis is insufficient because it fails to account for the impact of the de facto ban on coal both in the long and short terms. As explained above, new coal-fired EGU capacity will remain a viable economic option in the absence of this proposed rule and the proposed rule will thus result in a de facto ban on new coal-fired capacity. This fundamentally rebuts EPA's "zero cost' conclusion and demonstrates the arbitrariness of EPA's analysis.
Commenter 10051 states they recommends that EPA conduct a more in-depth cost benefit analysis regarding CCS implementation and that this additional cost-benefit analysis should assess the increased cost of electricity that utilities will pass on to consumers as a result of the requirement for partial CCS.
The EPA did consider the costs and benefits of the proposed rule, as required by Section 317 of the Clean Air Act, as well as by Executive Orders 12866 and 13563. This analysis is presented in the Regulatory Impact Analysis for the regulation. The analysis with respect to the proposed standard is found in the draft RIA, which was part of the record for the proposed rule.  See CAA section 317 (b).  This analysis also satisfies the economic assessment called for under section 317 of the Clean Air Act and is, for purposes of section 317(d), in the EPA's judgment, as extensive as practicable taking into account the agency's time, resources, and other duties and authorities.  This analysis is presented in the Regulatory Impact Analysis for the regulation (and, for purposes of CAA section 317 (b), was prepared in proposed form before publication of the proposed rule). The agency's analysis includes discussion of effects on energy use (see preamble section V.O.3 and sources there cited; 79 FR at 1480 and chapter 5 of the draft RIA).  The "effective date of the standard" (section 317(c) (2)) has no effect on the rule's costs, since the trigger date for new source status is the date of proposal.  In addition, the EPA has taken action to assure that sources under development are not subject to the final standard of performance.  See preamble section III.J.  The EPA also structured the proposed and final standard to avoid more costly alternatives, but rejected the 'business as usual' option as not reasonably fulfilling the requirement of section 111 (a) to base standards on the performance of the best system of emission reduction adequately demonstrated.  See 79 FR 1468-69; preamble section V.P.  The agency also noted the many opportunities (EOR and other by-product sales) as a further means of reducing regulatory costs.  79 FR at 1479; preamble section V.H.6.  Energy use and effect on consumer costs was likely addressed at proposal, and in the final determination.  79 FR 1480; preamble section V.O.3.

Commenters criticize this analysis as insufficiently robust because it showed (and continues to show) that the rule will have limited impact because new non-compliant coal capacity will not be built for reasons unrelated to the standards, chiefly well-documented price advantages NGCC has over coal.  The analysis shows that this price advantage will continue into the foreseeable future, and will continue even if natural gas prices rise (as the analysis predicts they will).  See RIA chapter 4.  Reasonable predictions from recognized sources, used government-wide, form the basis of this analysis.  See draft RIA chapter 5; RIA chapter 4.  With respect, it appears the commenters' chief criticism is the result of the analysis rather than the methodology.  The EPA continues to believe the regulatory analysis is sound and robust.

Finally, commenters chastise the EPA for not explicitly stating that the proposed RIA was also applicable to section 317 obligations.  The analysis fully satisfies the substance of the requirements of section 317, and that is what is important.  Cf. CAA section 307 (d)(8) ("[i]n reviewing alleged procedural errors, the court may invalidate the rule only if the errors were so serious and related to matters of such central relevance to the rule that there is a substantial likelihood that the rule would have been significantly changed if such errors had not been made").  Nor does section 317 require that analysis satisfying section 317 be labelled as such.
Renewables
Commenter 8971 states USEPA argues that increases in the supply of renewable energy will obviate the need for additional coal-fired generation. Commenter states that this is incorrect, noting first, EIA estimates that in 2040 renewable generation (including hydroelectric power) will make up less than 17% of U.S. electricity generation. This is obviously not a large enough share to crowd out coal-fired generation. Second, commenter states, intermittent generating technologies like wind solar, and other renewable sources is not a replacement for dispatchable sources like coal or natural gas that can provide power at all times regardless of weather conditions.
The EPA agrees that the relevant comparison is between baseload dispatchable technologies.  This is why a key cost comparison is between coal and nuclear.  See preamble section V.H.5.

Proposed Rule's Effect on Reliability and Affordability of Electricity
The proposed rule will impact reliability and affordability
Commenters (0585, 2471, 5604, 9731, 8974, 10967, 10239, 10396, 9723, 10387, 7533, 9471) state that the proposed rule will negatively impact reliability and affordability.
Commenter 0585 states, these rules have the potential to push energy costs up across the United States, thus forcing citizens and businesses to pay much more for energy in this country. Commenter says, all sectors of business will be impacted negatively as energy costs rise. Commenter urges the EPA to consider these factors as you move forward with the process of creating regulations.
Commenter 2471 states, the EPA's proposal will significantly drive up energy costs at a time when we are working our way out of the longest recession in US history, with negligible impact on global carbon emissions. Commenter says, any US GHG reduction plan must include a fuel-mix that is practical, reliable and reasonable in cost, and the plan must have a realistic timeframe to comply, along with consideration of the actual global impact from any US CO2 reductions.
Commenter 5604 states, the proposed regulation of CO2 and other greenhouse gases has the potential to impact electric grid reliability, damage our national and local economies and significantly increase electric rates. Commenter says, the proposed EPA regulation of CO2 will have a significant impact on the long-term reliability and affordability of electricity for our residents. Commenter asks for the EPA's consideration in this important matter and urges the continuance of reliable and affordable electricity.
Commenter 9731 states, that EPA should contemplate the long-term impacts of its regulation on the need for affordable power generation. 
Commenter 8974 states, EPA needs to be careful in crafting regulations that force utilities to rely almost entirely on one fuel and assuming that there would be no additional costs to the consumer. 
Commenter 10967 states, the proposed rule will dramatically inhibit companies from investing in the construction of new low-cost, high efficiency coal-fired power plants that would result in lower energy costs for residents and businesses. Commenter says, the new regulations will effectively ban new plants from being built and prevent states from generating more electricity with less fuel and fewer emissions. Commenter says, opportunities to provide economic stimulus and benefits from future energy efficiency projects and enhanced coal technologies will be lost. Commenter says, alternative approaches should be considered that will not harm the economy or endanger the affordable electricity supply of states.
Commenter 10239 states, there are significant concerns regarding EPA's regulation because of the potential impact it will have on energy prices and reliability and because of the potential precedent-setting nature of the approach on manufacturing sectors in the future. Commenter says, there are also concerns that the proposed rule will apply directly to future projects including cogeneration plants. Commenter says, EPA should withdraw this proposal and engage in a process with all interested stakeholders as to whether and how EPA should approach GHG regulation.
Commenter 10396 states, the proposal creates uncertainty for utilities making long-term investment decisions. Commenter says, once the NSPS has been established, the Administrator is required to review and revise the standard every eight years. Commenter says, EPA could tighten its standard in eight years requiring full carbon capture and sequestration for coal units and partial or full carbon capture for natural gas units. Commenter says, the current proposal is unreasonable and additional restrictions could be added in eight years which will jeopardize electrical reliability.
Commenter 9723 states, EPA should revise the emission limits for new units to address compliance concerns. Commenter says, if new EGUs are limited to high load operation through the very low emissions limits set in the proposal, regional transmission organizations may have to dispatch more fossil-fired electric generation resources than needed to assist in balancing the transmission system. Commenter says, applying too stringent of a CO2 emission limit to new EGUs could result in increasing emissions by creating inefficiencies in transmission grid management, requiring more than the necessary generation to be brought online to manage grid stability.
Commenter 10387 states, that it is necessary to have an adequate opportunity to plan, study and build the right generation options to keep electric service reliable, affordable, and sustainable. Commenter says, if decisions are made more difficult by regulatory uncertainty, then there will be a risk of being subjected to rising market prices or not having sufficient generation to meet demand. 
 Commenter 7533 states, if EPA imposes regulations which require compliance that is not technically possible to meet or economically feasible then the nation could experience a large price increase for electric power and harm the economy. Commenter says, coal continues to provide a low cost energy solution for power plants and that customers have heavily invested in protecting the environment and will continue to do so in the future. Commenter says, EPA should not create rules and regulations that are unattainable as the results will eliminate jobs and increase energy costs.
Commenter 9471 states, the proposed rule would effectively eliminate new coal-fired generation from the nation's energy portfolio and would even discourage new gas generation through the imposition of overly stringent standards. 
EPA understands that commenters have concerns about reliability and affordability, but disagrees with these comments. 

There are a number of sources of these concerns, including the potential for reduced fuel diversity, a diminished role for coal, and the potential for increased fuel costs.  EPA has considered all these factors, and believes the rule will have at most a negligible impact on reliability and affordability of power.  See the RIA, Chapters 4 and 5 for EPA analysis.  
 With respect to anticipated infrastructure needs, the rule will not result in fuel diversity problems for reliability.  This rule only applies to new sources of base load and intermediate load electricity, and does not affect existing sources.  Peaking units will continue to operate and be available for high load period to ensure continued reliability.  Even recognizing the potential for differences from EPA's projections, these projections show that the nation's electric generating mix will continue to be diverse, with coal accounting for a substantial share of generation well into the future (this finding is corroborated by EIA and many other independent forecasting groups).  Finally, EPA explored scenarios using alternative assumptions with considerably higher future electric demand and higher natural gas prices, and no scenario resulted in new conventional coal by 2020.  Independent analysis and projections from EIA confirm this trend. EPA does not project any change in energy prices as a result of this rule, and as such does not expect negative impacts on the affordability or reliability of electricity.  
 EPA also disagrees with other concerns in the comments that suggest that moving away from coal and toward greater natural gas for new generating capacity will result in a less reliable power system.  Natural gas infrastructure issues are entirely manageable under this rule.  Natural gas pipeline capacity has historically expanded to meet the needs of new natural gas generation capacity, and the same developments will happen in the future.  As the RIA and EPA modeling make clear, expected growth in natural gas requirements is well within historical limits.  See Chapter 4, generally, and Figure 4.2 specifically. The ability to manage pipeline infrastructure development is straightforward where additional capacity will be required to meet the requirements of generation already connected to the pipeline system, or added to the current pipeline network.  It is also standard practice in adding pipelines in areas not yet connected to the natural gas pipeline system.  Thus, the normal expansion process will address most cases where additional infrastructure is needed for continued reliable operation and new sources of fuel are added.  In the near term, there should be few additional infrastructure needs, as this rule does not affect the continued operation of any existing sources.  
 In the longer term, as the generating fleet turns over, much of the existing fossil generation will remain and continue to be diverse, while the normal infrastructure development noted above can accommodate much of the new demand.  Moreover, much of the new demand can be met by various forms of new renewable energy.  These new sources are becoming more competitive and are already reliably serving significant load previously served by older generation sources.  Many studies demonstrate the ability for these sources to serve as much as 30 percent of the total load in the US, and also identify how renewable capacity can assist in meeting  energy and reserve requirements, adding to the overall diversity of the generating fleet.

Also, as new combined cycle gas units are added and operate more in a baseload capacity, they are better able to support the long term contracting process because they can expect to have a steady stream of revenue to support the regular payments under such contracts.  This increased ability to support the longer term revenue stream also means that operators of NGCC facilities will provide greater support for the use of firm natural gas contracts.  These firm contracts will, in turn, support increased pipeline capacity to ensure the a reliable supply of gas where needed to forestall a recurrence of the "Polar Vortex" like winter emergency periods where natural gas and electricity peak demands intersect.  For these reasons, EPA believes the rule will aid in easing concerns over reliability as the mix of generating sources changes.
	
With respect to affordability, EPA expects the impact of the rule on costs to be negligible.  In the RIA, EPA has analyzed how natural gas prices that rise to unexpected, or even unprecedented levels, might affect costs, and concluded that even these unlikely scenarios would have no more than a small potential for impact on costs and, as a result, fuel reliability.  (See RIA, Chapter 5 for this analysis.)

The EPA's modeling, conducted using the Integrated Planning Model (IPM), as well as modeling conducted by the U.S. Energy Information Administration (EIA) showed that new generating capacity built through the period of analysis would be in compliance with the standard even in the absence of the regulation. This finding held true even under a number of alternative scenarios. As a result, the EPA projected there would be negligible costs, benefits, or energy impacts (including changes to energy prices) associated with the rule in the period of analysis. Additionally, there are not expected to be macroeconomic or employment impacts. See RIA Chapter 4.
Fuel diversity is needed for reasons of electric system reliability
Commenter 8937 states, a diverse portfolio of generating fuels is required to insure reliable cost effective power under all circumstances. Commenter says, the EPA's RIA indicates the rule will have negligible energy, cost and economic impacts by 2022. Commenter says, believing this rule will have no impact on the price of electricity, employment or the economy, ignores the significant reliability and cost concerns that flow from limiting generating fuel diversity and placing operating constraints on resources that will be needed to integrate renewables into the electric grid.
Commenter 8937 states, a case in point for Black Hills was the February 4-7, 2014 extreme cold weather event that resulted in natural gas curtailment for electricity generation, no wind farm output from two wind farms located in Cheyenne, Wyoming, Commenter says, Western Interconnection Bulk Electric System generation constraints causing resources to be sparse and transmission constraints causing additional supply flow issues-all resulting in dependence on our coal fired generation for a 2 day period to supply electricity to our customers, highlighting the critical importance of fuel diversity in maintaining a reliable supply of electricity.
Commenter 8937 states, by effectively preventing any new coal fired generation, this proposed rule jeopardizes the ability to hedge against future fuel price spikes and threatens the nation's reliable, affordable electric service.
Commenter 8937 states, the EPA states that new coal plants without CCS might be built in the period through 2020 in order to offer fuel diversity to a group of customers that are willing to pay a premium in electricity prices. Commenter says, the developer could add CCS to the plant and possibly rely on cost savings from EOR or in their customer's willingness to pay a higher premium. Commenter says, the Power4Georgians project that the EPA uses as an example of customers willingness to pay a premium, was designed as conventional coal without CCS in order to compete with natural gas. Commenter says, the "premium" the customers would pay would reflect the difference between the market price of gas-fired and coal-fired power. Commenter says, that premium is far less than the premium of an additional 50% or more in project costs for a coal plant with CCS. Commenter says, indeed, requiring CCS on this project will insure it never moves forward.
Commenter 9780 states in the Proposal and public record, EPA has gone to some lengths to address earlier stakeholder concerns about the need to be able to build coal plants as a hedge against the variability of natural gas prices. Commenter says, however, regardless of this additional analysis, the point remains that fuel diversity is needed for reasons of electric system reliability, not for the sake of diversity itself. Commenter says, even if a resource is not currently seen as cost competitive, market conditions may change unexpectedly, either for the short- or long-term, making use of different resources necessary and/or desirable to provide reliable (and affordable) generation at different times.
Commenter 9780 states as noted in their 2012 comments, the value of a separate standard is not just to ensure a diverse portfolio of generating technologies and fuels but also to ensure that there are economic alternatives should other technologies experience fuel supply disruptions or price increases (e.g., natural gas prices increase beyond expectations). Commenter says, electricity is dispatched on the basis of cost, with the lowest cost resources being dispatched first. Commenter says, in regulated markets, generators are required to provide the lowest cost service possible, and in competitive markets, market forces dictate that the lowest cost resources will dispatch first. Commenter states, thus, generators will "indeed, must" build and run the lowest cost generation source first. Commenter says, given the low cost of natural gas as a fuel currently, natural gas-fired plants now generally are dispatched before coal-fired plants. Commenter says, as a result, due to low fuel prices, lower capital costs and shorter permitting lead times, almost all new baseload generation built in the last several years has been natural gas-fired.
Commenter 9780 states, for example, as demonstrated this past winter and described in detail below, in times of natural gas supply disruptions and price spikes, coal-based units tend to offer lower cost generation. Commenter says, however, many of the coal-fired units that were relied upon for power are slated for retirement in the next several years, in part due to the costs of meeting current environmental regulations and the low cost of natural gas as a generating fuel. Commenter says, as a result, the availability of this alternative source of generation would be put at risk if the proposed standards are finalized: many existing units are retiring and it is not currently cost-effective to build coal-fired EGUs with CCS.
Commenter 9780 states as noted above, it is important that all baseload generation options, including conventional coal-fired plants, continue to be available resource choices. Commenter says, the EPA acknowledges this when it indicates that coal-based units might also be built for non-economic reasons and that there are "a range of factors that a particular company may consider when evaluating new generation options, such as fuel diversification." 79 Fed. Reg. at 1443. Commenter says, the importance of having a significant amount of baseload generation resources (of all technologies and fuels) to dispatch was demonstrated during episodes of extremely cold weather across the country in January and February 2014.
Commenter 9780 states, the effects of these extreme weather episodes on natural gas supply collectively serve as a case study on the importance of having a significant amount of generation available from a variety of technologies and fuels, and on the dangers of becoming overly reliant on any single technology or fuel for electric generation. Commenter says, all fuels, including coal- and oil-fired generation, were relied upon during the polar vortex episodes. Commenter says, the cold weather this winter and the resulting record demand for natural gas, both for heating and for power generation, has shown that the natural gas distribution network can become constrained in high-demand scenarios as a result of a demand "double peak" in winter months.
Commenter 9780 states, the Scott Madden report also highlights the region's growing reliance on natural gas, and notes that the coal- and oil-based power plants that helped the region meet the recent spike in demand are being retired and largely replaced by renewables, which require gas-based plants to run more to provide power when renewables, which are intermittent resources, are not available.
Commenter 9780 states, yet this situation is easily avoidable by creating a workable standard for coal. Commenter says, as existing units continue to retire due in part to current and future regulations, it is critical that EPA develop a workable standard to ensure that new conventional coal-based facilities can be built and be available as another reliable baseload resource. 
Commenter 9401 states, when U.S. energy costs rise because of regulations promulgated by EPA to reduce GHG emissions, industries may not be able to compete with foreign competitors and may shut down U.S. facilities or move them offshore resulting in "GHG leakage". Commenter says, forcing facilities offshore accomplishes nothing environmentally, and damages the domestic economy and employment.  
Commenter 9401 states, industries require highly reliable power and any EPA action that results in diminution of reliability increases both costs and creates a safety hazard for employees. Commenter says, this winter, manufacturers across the country were forced to curtail use of electricity because of electric generation reliability problems. Commenter says, this resulted in reduced manufacturing production rates, if not the shutdown of the entire manufacturing facility. Commenter says, power reliability is maintained by having a diverse fuel mix, as well as by installing a robust supply of distributed generation such as industrial combined heat and power (CHP) and waste heat recovery (WHR). Commenter says, enhancing end-use energy efficiency also promotes power reliability by relieving transmission congestion and limiting demand growth. Commenter says, it is vital that the rule is cost-effective and will not increase electricity prices or reduce electric reliability thereby not causing manufacturing facility production curtailments, causing safety issues for our employees, and GHG leakage. 
Commenter 9195 asks the question, do regulated parties have an interest in "fuel diversity"? Commenter asks, would such an interest support construction of coal-fired power plants in the absence of the proposed NSPS? 
Commenter 9777 states, EPA should reconsider how this rule adversely affects fuel diversity necessary for electric reliability by effectively banning new construction of new coal-fueled units. 
Commenter 9397 states, diversity of energy supply is critical for keeping energy costs reasonable. Commenter says, the consideration of coal as a viable fuel option would be impacted by the technical infeasibility of the proposed standard.  
Commenter 2864 states, conventional generation is needed as reliability requires EGUs to be able to: provide reactive power support which requires spinning resources, increase or decrease output immediately to respond to system frequency changes, limit production as needed for the promotion of reliability, and provide inertial response. Commenter says, non-conventional resources do not have the ability to provide these operating characteristics.
Commenter 2864 states concerns that the CCS technology will significantly increase electricity costs for consumers. Commenters says, conventional generation is very important for maintaining a reliable, stable, and low cost grid. Commenter says, utilities must be given credit for early investments and state and regional flexibility must be provided. Commenter says, EPA needs to consider a total system approach that includes consideration for emission reductions from renewable resources and customer load management programs versus a plant by plant approach.
Commenter 8024 states, the move toward natural gas becoming the dominant source of base load and peak power could have repercussions for energy security and electric reliability. Commenter says, without sufficient coal or other generation options, sustained cold weather events could lead to natural gas supply disruptions that could compromise the electrical system. Commenter says, the growth in international trade in natural gas cold also expose the power industry to significant price shocks or supply disruptions.
Commenter 9773 states, the requirements and costs imposed under this rule have the potential to impact the reliable delivery of electricity. Commenter says, this problem is compounded if utilities are forced to rely primarily on natural gas in replacing coal-fired generation.  
 EPA disagrees.  See EPA response at the beginning of this section.
Foreclosing the use of coal-fired generation threatens electric reliability
Commenter 9196 states, foreclosing the use of coal-fired generation threatens electric reliability. Commenter says, given the regulatory uncertainty related to future EPA regulations on a wide variety of energy sources (and not just coal) keeping all options on the table for energy generation, as the President has suggested multiple times, is essential to maintaining America's energy supply. Commenter says, in recent years, coal-fired power plants have provided approximately 40 percent of the electricity used by US consumers and businesses each year. Commenter says, the number is lower now due to pending EPA regulations and market conditions associated with the price of natural gas, but even today, notwithstanding the historically low cost of natural gas and newly adopted regulatory obstacles for coal, Administrator McCarthy has noted that "coal will continue to represent a significant source of energy for decades to come."
Commenter 9196 states, as a result of the combination of EPA's regulations, including the proposed rule and the upcoming 111(d) rule for existing coal-fired units, the country may experience a shortage of electricity, and the reliability of our electricity grid will face substantial risks. Commenter says, the loss of future coal-fired generation, investment in current coal-fired generation, and closures of existing coal-fired generation capacity that may result from the combination of the proposed rule and other EPA regulatory actions risk a variety of reliability problems. Commenter says, in most cases, coal-fired plants cannot be replaced overnight by natural gas plants, as the time it takes to install pipeline and other infrastructure necessary even to begin conversion of an old plant or construction of a new one is considerable. Commenter says, additionally, as David Wright testified recently, coal-fired generation is an important aspect of "resource diversity," and EPA needs to "recognize the needs of States and regions to deploy a diverse portfolio of cost-effective supply-side and demand-side resources based on their own unique circumstances and characteristics."
Commenter 9196 is concerned that the proposed rule establishes a future for electricity generation that is narrowly limited to a small group of technologies, some of which do not even exist commercially at this time, and that EPA's plan for the future risks disruption in the reliable supply of electricity. Commenter says, last winter unleashed brutally cold temperatures on citizens around the U.S., teaching our country some hard lessons about the importance of reliable and affordable electricity, and the need for EPA to be very careful about limiting the flexibility and diversity of our electricity generation options. Commenter says, the cold weather during the winter spiked natural gas prices, caused shortages of propane used to heat many homes, and exposed the fact that without fuel flexibility our country could face serious electricity reliability problems in the future. 
Commenter 9196 states, the cold weather this winter made it clear that coal-fired generation, much of which is currently scheduled to be retired as a result of EPA rules, is vital to the reliability of our electricity supply. Commenter says, in some areas, coal-fired plants thought to be obsolete were discovered to be essential to reliability, and one of the nation's largest electricity generators reported that 89 percent of the coal-fired generation slated for retirement by 2015 as a result of EPA rules was needed to supply electricity during the cold weather because natural gas and other alternatives were not suitable to address extreme conditions. Commenter says, these events were not isolated, as electricity generators in Texas and the Southeast faced extreme demands and had to take measures to ensure that coal-fired generation was available, even as those plants faced retirement in the coming years.
Commenter 9196 states, our electricity supply cannot rely on alternatives to coal to fill the gap that will be left by retired coal plants and a lack of investment in new coal technologies. Commenter says, in a review of the last winter, the Federal Energy Regulatory Commission (FERC) concluded that "cold temperatures stressed the bulk power system with high loads, increased generator forced outages, and other challenging operating conditions" and noted that "[w]ind turbines were also affected by the cold, with some wind turbine models reaching their minimum operating temperatures." Commenter says, daily use of natural gas reached a record high of 90.6 billion feet during this year's winter and prices soared to more than $5 per million Btu, according to the Energy Information Administration. Commenter says, additionally, as the CEO of a leading energy company explained, during "[o]ur peak demand between 7 and 8 am, which is when the peak is, there was almost no solar available because the sun is not up, so we need to have a system that can address those requirements and be prepared to provide the service our customers expect and the reliability they expect in those periods. That is the beauty of a portfolio."
Commenter 9196 states, the EPA needs to carefully consider the consequences of polices that may not allow for a flexible and reliable supply of electricity, because the impacts of reliability problems can be devastating. Commenter says, the downside impacts of reduced electric reliability are substantial and must be taken into account in any responsible analysis of the proposed rule. As ISO New England has stated:
"A reliable supply of electricity is a foundation of our prosperity and quality of life. Without it, our world literally grinds to a halt; businesses cannot plan and operate productively, hospitals and schools cannot provide their essential services, and residents cannot depend on the electricity they need simply to live their daily lives. Without reliable electricity, the financial and societal costs would be enormous. The Institute of Electrical and Electronics Engineers of the U.S. (IEE-USA) has further observed that even minor occurrences in the electric power grid can sometimes lead to catastrophic "cascading" blackouts, and that the loss of a single generator can result in an imbalance between load and generation. The resulting blackouts cause incalculable economic damage. For example, the direct costs to high-technology manufacturing in the San Francisco Bay Area alone during the California blackouts alone ran as high as one million dollars a minute due to lost production, and the relatively brief Northeast blackout of 2003 cost business about $13 billion in lost productivity. These are costs that our economy and communities cannot afford to bear, and EPA needs to carefully consider reliability concerns before moving forward with the proposed rule."
Commenter 9401 states, coal must remain as a viable low-cost energy source for power generation. Commenter says, the U.S. cannot have a reliable electricity system if it is too dependent upon natural gas and we have already crossed the line in various regions of the country. Commenter says, on a Btu basis, coal and natural gas must be allowed to compete. Commenter says, price competition between coal and natural gas is critically important in keeping electricity prices low and protecting the reliability of supply. 
Commenter 9003 states, energy reliability is critical and the future is uncertain. Commenter says, the implementation of this proposal ensure no new coal powered generating plants will be built regardless of state energy needs or the associated costs. 
Commenter 10083 states, the proposed rule should better reflect the impacts and challenges of eliminating coal generation as an electricity resource option, until CCS becomes an available control technology that can perform dependably.  
Commenter 10607 states, grid reliability and security will decrease as a result of EPA's proposed rule. Commenter says, retirement of coal-fired EGUs and increased reliance on natural gas by the power industry are linked to spikes in electricity prices and reliability issues. Commenter says, the proposed rule would prevent replacement of coal-fired base load, creating a gap that natural gas cannot completely fill, thereby leading to decreased reliability and security of the power grid. 
Commenter 10662 states, the proposed rule will have major negative consequences for grid reliability. Commenter says, if natural gas supply and price projections are wrong, and there is not adequate coal-fired power available, there will be a major impact on rate payers, reliability and grid stability. Commenter says, the effective ban of coal-fired generation threatens the reliability of the electricity grid. Commenter says, a shortage of available power generation in harsh winter weather is a serious reality. Commenter says, during these cold times, natural gas curtailments are the reduction of gas deliveries due to a shortage of supply or because demand for service exceeds a pipeline's capacity. Commenter says, usually there is a hierarchy of customers, in which some may be required to partially or totally cut back gas usage before others. Commenter says, industrial users, for example, are usually curtailed before service to residential users is reduced. 
The final standard of performance is not a ban on new coal capacity.  The standard of performance is achievable by multiple means (not all of which involve sequestration), and can be done at reasonable cost.  The commenters posit a situation where natural gas prices rise precipitously during the review period.   However, as explained in RIA chapter 4.4, natural gas prices are expected to increase after 2020 in all scenarios. However, rising natural gas prices through 2040  -  including in EIA's low gas/oil resource scenario - are still not sufficient to support new, non-compliant coal-fired generation through 2022 in these scenarios. This demonstrates that natural gas prices do not have to continue at currently low levels for NGCC to maintain its economic advantage over coal-fired technologies. In addition, in Chapter 5 of the RIA, the EPA presents analysis of the potential costs and benefits of the standards under a range of natural gas prices, including unprecedentedly high gas prices. It is only when gas prices reach levels not observed in EIA data back to 1996 that an NGCC unit would become less economic than a non-compliant coal unit.   
 Commenter 9666 states a final NSPS that is too stringent could undermine the reliability of this nation's electricity supply because owners and operators might be reluctant to invest in new NGCC generation. Commenter concludes, for these reasons, EPA should undertake further assessment of the proposed NSPS for NGCC EGUs and repropose the standard based on the best information available and consistent with EPA's established practice for setting an NSPS (based on 99 percent compliance among facilities in the category).
First, most commenters asserted that a too stringent NSPS would result in more investment in new NGCC.  (In any case, EPA's analysis shows more investment in new, compliant NGCC as part of the baseline, for reasons unrelated to the final standard of performance).  Second, a best system of emission reduction obviously does not have to be a standard that most existing sources are presently achieving.  See preamble section III.H.3; Portland Cement 1, 486 F. 2d at 391.
National policies that diminish coal as a fuel choice jeopardize reliability and affordability 
Commenters (7994, 9407, 10097, 10952) comment on diminishing coal as a fuel choice jeopardizing reliability and affordability.
Commenter 7994 states, while they recognize that the agency action is undertaken at the request of the President, a standard that effectively eliminates coal as a generating resource goes too far and jeopardizes the reliability of the electric grid. Commenter says, they believe that regulating CO2 from new power plants will significantly increase electricity costs and hurt residential, commercial, and industrial customers, as well as impact reliability in certain parts of the country.
Commenter 10952 states many electric energy providers in the wholesale electric and gas markets recognize there are already significant impediments to providing reliable and affordable electricity under the present circumstances where significant baseload nuclear and coal-fired EGUs face retirement. Commenter says, many additional coal-fired EGUs will be retired because of the recent CAA Section 112 regulations, and as previously stated, under this proposal no new coal-fired EGUs will be built, making natural gas EGUs the remaining choice for new baseload electric generation.
Commenter 10952 notes the following points:
      - There are both physical gas pipeline constraints and gas-power process issues that need to be addressed to deal with the increasing growth of natural gas-fired generation.
       - Increased reliance on natural gas-fired generation will likely lead to both greater risk of electric reliability deficiencies and higher costs for consumers on future critical operating days. At times this winter gas was not available at any cost. When available in some areas the gas price was twenty times the monthly index price.
      - This past winter ACES itself experienced firsthand numerous gas and electric operational, physical, and process challenges that had profound impacts on the performance of our Members' loads and generation fleet. 
      - The greatest challenges are in the East, but impacts were observed all the way to California.
Commenters (9407, 10097, 10952) state in summary, uncertainties about natural gas supply and price set natural gas generation apart from coal generation where electricity costs are driven by capital outlays, not by uncertain fuel costs or availability. Commenters say, for these reasons national policies that effectively negate or even significantly diminish coal as fuel choice for baseload electric generation place both electric reliability and affordability in jeopardy.
Commenters (10097, 10952) state considering the importance this proposal places on of the need for natural gas availability, based on this rulemaking's record, EPA has apparently spent little effort actually examining issues surrounding natural gas transportation infrastructure available to supply natural gas to electric generating facilities that must be strategically located throughout the nation to support electric grid reliability. Commenter 10952 says, EPA appears to base availability assumptions solely on available natural gas reserves coupled with recent low prices. Commenter says, while natural gas may be available at gas transmission hubs, its availability on needed generation sites is fundamental in determining whether its rational to promulgate a rule that leaves natural gas as the only practical choice for future fossil-fuel baseload generation. Commenter says, at a minimum, significant construction of additional pipelines and infrastructure would be needed. Commenter says, as stated previously, they do not dispute that significantly more natural gas is being utilized for electric generation than the recent past and that this trend is likely to continue. Commenters (10097, 10952) say, what is at issue here is whether this fuel is certain to be available at sites where new baseload generation may be needed to replace retiring coal-fired units or at new sites where new baseload generation is required for additional reliability purposes. Commenters state, such certainty is fundamental to this proposal rationality.
Commenter 10952 states that two recent studies by the Interstate Natural Gas Association of America (INGAA) address additional needs for gas pipeline infrastructure to meet increasing demands under several scenarios ranging from high to low increased natural gas market demand scenarios. Commenter says, under the scenario of increased natural gas needs within the electric utility sector, a very significant amount of mainline and lateral miles of new pipelines to power plant sites would need to be constructed. Commenter says, as these studies identify, while INGAA believes the physical capabilities are available to meet such needs, numerous obstacles beyond the control of the pipeline builders could "delay or derail" efforts to meet these projected needs. Commenter says, opposition by multiple stakeholders including landowners, environmental groups, and groups having competing interests as well as federal/state jurisdictional impediments well outside the control of EPA could delay significantly needed construction of additional pipelines. Commenters (9407, 10952) say, while additional pipelines will be necessary to sustain grid reliability and provide electric service to consumers at a reasonable cost, EPA has provided no information in connection this rulemaking to show that it has evaluated the timely need of additional gas supply capacity as a result of this rulemaking.
Commenters (10097, 10952) state, it is quite remarkable that EPA has either ignored these natural gas availability and pricing questions or has failed to realize that any reasonable evaluation of this proposed rule must include them. Commenters conclude, at either rate EPA's failure to include a reasoned analysis here is yet another deficiency that makes this proposal arbitrary and capricious.
Commenter 9401 states, EPA has not evaluated generation and reliability costs at "peak" electricity and natural gas demand and that reliability is a safety issue. Commenter says, natural gas delivery is dependent upon, among other things, pipeline capacity that is limited in its ability to deliver. Commenter says, as experienced this winter, natural gas demand for heating homes, industry and power generation exceeded the capacity of pipelines in several portions of the country. Commenter says, the shortfall of natural gas availability led to both electricity and natural gas outages, and staggering spot prices for both electricity and natural gas for consumers. Commenter says, the industrial sector was curtailed for both electricity and natural gas which forced them either reduce or stop production of our products at great cost. Commenter says, these costs must be included in the cost-benefit analysis.
Commenter 9401 states, the reliability of power due to lack of fuel diversification endangers the safety of homeowners who rely upon natural gas and electricity to keep their homes heated in the winter and cool in the summer. Commenter says, there is also a safety threat for manufacturing employees. Commenter says, EITE industries operate facilities that have high pressure vessels and/or furnaces that operate at thousands of degrees Fahrenheit and if the power goes off without warning, employee safety becomes an issue. 
Commenter 9777 states, EPA acknowledges that power companies are still likely to construct new coal-fueled EGUs to replace existing baseload or demand-following capacity or for purposes of fuel diversity. Commenter says, the costs associated with this regulation would likely prohibit new coal-fueled generation construction absent a substantial increase in wholesale power prices. Commenter says, this regulation harms and disincentivizes the replacement and/or expansion of existing baseload and demand-following capacity that helps ensure fuel diversity which is vital to maintaining a reliable, competitive, and cost-effective power supply. Commenter disagrees with EPA's assumption that gas prices will remain at their current low levels for the indefinite future and does not take into account the benefit of fuel diversity to buffer against unexpected supply and price fluctuations.
Commenter 9777 states, the additional cost burdens associated with this rule will prevent the consideration of coal- generation construction unless a significant electricity cost increase can overcome those significant burdens. Commenter says, it will be the consumers who will bear the economic burden of this rule, either by the decreased energy supply diversification that will make U.S. energy more dependent on natural gas or by the cost associated with construction subject to this proposed rule. 
The EPA disagrees that these final standards diminish the role of coal as a fuel choice and thereby jeopardize reliability and affordability of electricity. As described in the rule preamble, the electricity sector is undergoing a period of intense change. Between 2000 and 2013, approximately 90 percent of new power generation capacity built in the U.S. has come in the form of natural gas or renewable energy facilities. This is primarily the result of historically low natural gas prices.
The proposed rule is Inconsistent with sound energy policy and sacrifices fuel diversity
Commenters (10095, 10388) provide comment on the rule's inconsistency with sound energy policy. 
Commenter 10095 is concerned about the proposed rule's impact on the fuel diversity of the nation's electricity supply. Commenter says electric utilities' ability to maintain their diverse generating fleets helps protect customers against fossil fuel price volatility and potential supply disruptions. Commenter says the proposed rule, however, would discourage the construction of new coal-fired EGUs and the related development of carbon capture and storage (CCS) and other new control technologies. Commenter says rather than encourage a diverse electricity supply, the proposed rule heavily favors the construction of new, natural gas-fired combined-cycle units. Commenter says the underlying assumption that natural gas prices will remain low indefinitely contradicts historical price trends.
Commenter 10095 states EPA's proposed rule is a risky undertaking that would substantially narrow the future fuel diversity of the nation's electricity supply, which can ultimately impact the reliability and affordability of electricity and thus jeopardize the nation's future economic strength. Commenter says EPA assumes that "few, if any solid fossil fuel-fired EGUs will be built in the foreseeable future [because] electricity generators are expected to choose . . . natural gas combined cycle[s] . . . ." Commenter says EPA ignores the fact that its actions have already forced many companies to change their planning assumptions related to coal. Commenter says leading up to the publication of the 2012 proposed rule, many companies, including Southern Company, regularly restricted their planning models from considering the prospect of new coal-fired power plants without CCS even if the option were otherwise economic. Commenter says companies were discouraged from considering new coal-fired power plants without CCS where, even if not the absolute lowest-cost, the option was a desirable alternative due to qualitative features, such as stage of development, operating characteristics, and fuel diversity. Commenter says this proposal entirely prevents companies from building coal considering that integrated CCS is not Adequately Demonstrated. Commenter says if the rule is finalized as proposed, EPA will continue to hinder the ability of utilities to leverage fuel diversity to provide reliable and affordable service to its customers in the years to come.
Commenter 10095 realizes the danger of disregarding the uncertainty of future fuel prices and the potential benefits of utilizing a variety of fuels to mitigate those uncertainties. Commenter is dedicated to providing a diverse electricity generation portfolio to the benefit of approximately 4.4 million customers in the Southeast, nearly half of whom earn less than $40,000 per year. Commenter says in 2012, across the Southern Company system, fuel costs were reduced by over $1 billion by leveraging a diverse fuel mix to the benefit of its customers. Commenter says and while natural gas has been relatively cheap in the past few years, the ability to invest in and dispatch other generation resources (e.g., coal) is vitally important to maintaining a reliable and cost effective electricity supply when natural gas prices fluctuate; which history, especially recent events this past winter, proves is inevitable. Commenter says in fact, in the first quarter of 2014, Southern Company took advantage of its fuel diversity during a period of higher natural gas prices to deliver over $100 million in fuel cost savings from using coal over natural gas.
Commenter 10095 states it is in the national interest for utilities to have the opportunity to maintain generation fleet diversity in order to hedge against fuel price fluctuations and thereby protect customers. Commenter says fuel cost variability has been a reality for the utility industry for all of its existence. Commenter says for decades, available coal generation has mitigated against natural gas price increases and vice versa. Commenter says the wide pendulum swing of fuel costs can only be dampened by maintaining a diverse portfolio of generation assets. Commenter says, for their company, a balanced generation portfolio is not merely an objective-it is an obligation that comes with the Company's duty to serve its customers.
Commenter 10095 states for example, recent analysis conducted by one of its affiliates, Georgia Power Company, assessed the impact that various plausible natural gas price forecasts for the year 2020 would have on the most cost-effective mix of generation resources. Commenter says in that analysis, natural gas prices on the lower end of the expected range were projected to result in as much as 50 percent of generation being provided by natural gas and only 18 percent of generation from coal. Commenter says yet, under a higher natural gas price scenario, the Company would minimize costs for its customers by generating only 28 percent from natural gas and 40 percent from coal. Commenter says the EPA's proposal would prevent utilities, like Southern Company, from continuing to develop a fleet that relies on diverse fuel mixes for the benefit of their customers.
Commenter10388 states, as currently drafted, the rule is inconsistent with sound energy policy and would make America less attractive when competing for location of additional employers: affordable, reliable electricity.
The EPA has structured the final standard in partial response to the comments both to this proposal, and the 2012 proposal, that it was important for utilities to preserve fleet diversity in order to hedge against fuel p[rice fluctuations (e.g. Southern Co., commenter 10095). In assessing the cost of the final standard of performance, the EPA carefully compared the cost of the rule to fossil fuel-fired EGUs (expressed as LCOE) to the cost of new nuclear facilities.  This comparison is reasonable.  These are the two principal non-NGCC baseload dispatchable technologies.  The costs are in the same range.  See preamble section V.H.5 and V.I.1.
Moving away from coal and away from energy diversity is an irresponsible policy choice
Commenter 8954 states, for American families, the consequences of a shift in the energy mix away from coal are equally concerning. Commenter says the longest running recession in U.S. history has already caused great hardship for families. Commenter says, the cost of energy as a percentage of pre-tax income in the last decade has nearly doubled for the middle class. Commenter says, six in ten Americans say a $20 per month increase in utility bills would create hardship.  Commenter says, one in three Americans qualifies for energy assistance.  Commenter says, pushing more Americans towards having to choose between food or medicine or fuel - with negligible environmental results by EPA's own admission - is untenable. Commenter says, higher energy prices are regressive and will have the biggest impact on those who can least afford it. 
Commenter 8954 states others, including those in the regulatory arena, are expressing concern about this close call and the ability to reliably meet electric demand. Commenter says, at an April 1, 2014 Federal Energy Regulatory Commission (FERC) Technical Conference, FERC staff presented their analysis of the natural gas and electricity markets during the "conditions of severe stress and market pressures" this winter, stating "The RTOs and ISOs declared emergency conditions on several occasions and some implemented emergency procedures, including emergency demand response, voltage reduction, emergency energy purchases, and public appeals for conservation." Commenter says, FERC's Acting Chairman Cheryl LaFleur stated in testimony before the Senate Energy and Commerce Committee on April 10, 2014, "Indeed, I believe that reliability is job one, a fundamental responsibility for FERC and the electric industry. From my past experience working directly for electricity and natural gas customers, I know firsthand how hard even a short outage can be on families, businesses, and communities. And a major interruption in service could have devastating effects on our nation's citizens and economy, whether it is caused by severe weather, a cybersecurity incident, or a physical attack". 
EPA disagrees: any impacts of this rule on the choice of coal as a fuel for electric generation will not be harmful for reliability.  This rule only applies to new sources of base load and intermediate load electricity, and does not affect existing sources.  EPA's projections show that the nation's electric generating mix will continue to be diverse, with coal accounting for a substantial share of generation well into the future (this finding is corroborated by EIA and many other independent forecasting groups).  Finally, EPA explored scenarios using alternative assumptions with considerably higher future electric demand and higher natural gas prices, and no scenario resulted in new conventional coal by 2020.  Independent analysis and projections from EIA confirm this trend of no new conventional coal. EPA does not project any change in energy prices as a result of this rule, and as such does not expect negative impacts on the affordability or reliability of electricity.  EPA also disagrees with other concerns in the comments that suggest that moving toward greater natural gas will result in a less reliable power system.  Natural gas infrastructure issues are entirely manageable under this rule.  Natural gas pipeline capacity has historically expanded to meet the needs of new natural gas generation capacity, and the same developments will happen in the future.  This is particularly true in the case of comments where additional capacity will be required to meet the requirements of generation already connected to the pipeline system.  It is also true for areas not yet connected to the natural gas pipeline system.  Thus, the normal expansion process will address most cases where additional infrastructure is needed for continued reliable operation and new sources of fuel are added.  In the near term, there should be few additional infrastructure needs, as this rule does not affect the continued operation of any existing sources.  In the longer term, as the generating fleet turns over, much of the existing fossil generating will remain and continue to be diverse, while the normal infrastructure development noted above can accommodate much of the new demand.  Moreover, much of the new demand need not be met by natural gas, but by various forms of new renewable energy.  The new sources are becoming more competitive and are already reliably serving significant load previously served by older generation sources.  Many studies demonstrate the ability for these sources to serve as much as 30 percent of the total load in the US.EPA disagrees.  See also response at beginning of this section.

Also, as new combined cycle gas units are added and operate more in a baseload capacity, they are better able to support the long term contracting process because they can expect to have a steady stream of revenue to support the regular payments under such contracts.  This increased ability to support the longer term revenue stream also means that operators of NGCC facilities will provide greater support for the use of firm natural gas contracts.  These firm contracts will, in turn, support increased pipeline capacity to ensure the a reliable supply of gas where needed to forestall a recurrence of the "Polar Vortex" like winter emergency periods where natural gas and electricity peak demands intersect.  For these reasons, EPA believes the rule will aid in easing concerns over reliability as the mix of generating sources changes.
Proposed rule takes a risk on natural gas price trends
Commenters (1959, 9497, 4710, 8501, 9775, 10024, 10095, 10393, 10238) comment on the risk associated with natural gas price trends. 
Commenters 1959 and 9497 states, as demonstrated by cold snaps just this winter, natural gas prices are volatile and spike even during shorter-term weather events. Commenters say, this has an immediate adverse effect on consumer electric bills. 
Commenter 1959 states, coal and its stable price is a long-term proven hedge against natural gas volatility and is critical if we are to continue to provide affordable electricity for our members. Commenter says, while new, unconventional natural gas supply from shale has played a huge role in lowering natural gas prices; even this increased gas supply has not changed the built in volatility of natural gas. Commenter says, this is because price volatility is correlated with business cycles, weather extremes, and pipeline infrastructure issues. Commenter says, again, we are experiencing this with the 2014 winter weather across much of the nation. Commenter says, because we have an obligation to provide reliable electric service to our members, we cannot ever find ourselves in a situation where all of the dispatchable electricity generation comes from a single fuel source, lest disruptions in fuel supply should create electricity shortages. Commenter says, during the polar vortex this winter, high demand for electricity, high demand for gas and localized gas supply disruptions forced the grid to rely heavily on coal-powered resources to maintain reliability.
Commenter 4710 states, in its proposed rule, the EPA states that utility companies value fuel diversity. Commenter says, however, by effectively banning the use of coal for new electrical generating units, the proposed rule will increase utilities' reliance on natural gas, which has been subject to wide fluctuations in price and supply, as shown most recently by the 2014 spikes in natural gas prices throughout the Midwest and Eastern United States.
Commenter 8501 states, by legally mandating natural gas as the future fuel of choice, the EPA has chosen to place the nation's energy development bet on a fuel with a history of wild fluctuations and frequent shortages. Commenter says, that bet will leave the country vulnerable to wide swings in electricity prices, potential shortfalls in reliability, and unable to respond to long-term energy development needs should the natural gas market become too costly for widespread electrical generation.
Commenter 9775 states, the EPA's decision to forego the low-cost base power of coal-fired power plants and replace it with generally higher cost, more volatile alternatives will likely result in greater instability in electricity prices. Commenter says, historically, natural gas prices have been significantly more volatile than those of coal. Commenter says, forcing utilities to rely on a more volatile fuel source potentially puts utilities and their customers at increased economic risk. Commenter says, this rule will lead to a base-load electrical generation system that is abandoning the proven stability and affordability of coal, and the accompanying ability of communities and states to hedge against the volatility and price of other sources of power.
Commenter 10024 states, fuel diversity is key to ensuring that electric utilities can deliver power reliably. Utilities must have the ability to use coal and natural gas-fired generation, as well as renewables and other sources. Commenter says, the harsh winter of 2014 and its impacts on short-term natural gas prices demonstrates that EPA needs to be very careful in crafting regulations that force utilities to rely almost entirely to one fuel and assuming that there would be no additional costs to the consumer.
Commenter 10095 states, in its proposal, the EPA asserts that utilities will not build new coal-fired power plants in the foreseeable future and thus the rule has no detrimental economic impact based on two high-risk gambles: (1) that the results of its short-term evaluation are applicable to a rule with long-term impacts and (2) that EPA's snapshot of forecasted natural gas prices will be accurate. Commenter states not only is reliance on forecasted information to make absolute and permanent policy decisions dangerous, EPA's proposal exacerbates the matter by arbitrarily limiting the scope of the analysis to the year 2022. Commenter says, while EPA claims that it reviewed a range of fuel prices and other scenarios, EPA artificially constrained these scenarios by considering only the impacts on new generation construction in the immediate future. Commenter says, EPA then recklessly extrapolates this to make the claim that no new conventional coal plants will be built, period, under any scenario, even in the absence of this rule. Commenter says in order to responsibly serve customers and make the best investment decisions, utilities like Southern Company must utilize much longer planning horizons- decades, not years. Commenter says in addition, utilities must have the flexibility to make adjustments when forecasts do not match up to reality. Commenter says, in coming to the conclusion that no new conventional coal plants will be built in the foreseeable future, EPA's flawed analysis effectively makes the rash assumption that the low natural gas price trends currently reflected in the market will continue indefinitely.
Commenter 10095 states as illustrated [in Figure 1 of the original document] (Henry Hub Natural Gas Spot Price, pg 9) natural gas prices have been historically volatile and unpredictable. Commenter says, just recently, for example, wholesale power prices in New England jumped 55 percent reaching record levels in 2013 due to winter weather, high natural gas prices, and natural gas pipeline constraints. Commenter says, yet, EPA presumes natural gas prices will consistently remain at all-time lows. Commenter says, projections of natural gas prices from only a few years ago, however, have proven to be wildly incorrect. Commenter states, this rule relies on these potentially erroneous projections that may not only shift, but may drastically shift, and subjects the nation's energy future to such uncertain forecasts. Commenter concludes, the well-being of all electricity customers should not rest on such shifting sand.
Commenter 10393 states, the proposed rule also assumes continued low natural gas prices. Commenter says, as history indicated, predicting the price of natural gas is fraught with error and EIA has missed the mark almost every year. Commenter says, while natural gas prices are currently considerably lower than in 2009, they are twice the price from 2012. Commenter says, the harsh winter of 2014 and its impacts on short-term natural gas prices demonstrates that EPA needs to be very careful in crafting regulations that force utilities to rely almost entirely to one fuel and assuming that there would be no additional costs to the consumer.
Commenter 10238 states, EPA's proposed standards will push the industry primarily to natural gas and renewables. Commenter says, the current natural gas infrastructure may not be adequate to meet these needs, especially in instances of severe winter weather. Commenter says, these existing infrastructure issues should be addressed prior to imposing the proposed standards. Commenter says, EPA should allow a longer ramping-up phase so electric cooperatives can better prepare for the fuel and technology changes which can also help to better manage the increases to consumer electricity costs.
EPA disagrees.  Volatility is an inherent component of fuel markets, and choices of all fuels involve risks.  Volatility is generally defined as short term, but planning for new capacity is based on expected returns for a longer period and pertinent costs for customers are also general longer term.  Although there is greater historical variation in long term fuel prices for natural gas than for coal, both fuels are subject to variation in the long term (See, "Trends in structure of Electric Power Sector Limiting Amount of New Coal" Section B.4 and Figures 7 and 8 in the docket for this rule.).  Moreover, long term contracting and price hedging over shorter periods provide well developed mechanism to manage risk in natural gas markets.  Also, as new combined cycle gas units operate more in a baseload capacity, they are better able to support the long term contracting process because they can expect to have a steady stream of revenue to support the regular payments under such contracts.  This increased ability to support the longer term revenue stream also means that operators of NGCC facilities will provide greater support for the use of firm natural gas contracts.  These firm contracts will, in turn, support increased pipeline capacity to ensure the a reliable supply of gas where needed to forestall a recurrence of the "Polar Vortex" like winter emergency periods where natural gas and electricity peak demands intersect.  .  The combination of firm contracts and risk management through market mechanisms will provide the needed basis for managing natural gas pricing and delivery. For these reasons, EPA believes the rule will aid in easing industry concerns of both natural gas price fluctuations and supply concerns
The price and availability of natural gas are too speculative to make it the only practical choice for new baseload generation
Commenters (9601, 10043, 10097, 8024, 10662, 8032) state the price and availability of natural gas are too speculative to make it the only practical choice for new baseload generation. 
Commenter 10043 states, as for the electric grid, the proposed rule gives short shrift to reliability concerns. Commenter says, in recent years, the electric generation industry has closed many coal plants and built natural gas plants in their place. Commenter says, that works as long as natural gas is readily available at reasonable prices. Commenter says, but the fuel supply risk inherent in overreliance on a single fuel source has put a strain on the grid and the next two years will be critical for electric grid health. Commenter says, as illustrated by the 2013-2014 winter, in the absence of coal generation, low temperatures can create a serious natural gas fuel supply risk. Commenter says, simply put, the power supply this winter could not keep up with the demand. Commenter says, the natural gas pipelines, distribution lines, and storage facilities have not grown at sufficient rates to keep up with increasing reliance on natural gas generation, which led to extremely high gas prices in the months of January and February of 2014. Commenter says in addition, the natural gas supply for many power plants had to be curtailed because the pipelines were at their maximum capacity, leaving no capacity for natural gas combined cycle and peaking plants even though their generation output was needed. Commenter says, the high natural gas prices and lack of available natural gas led to very high winter electric prices, costs which foreshadow price impacts under the proposed rule, but which were not accounted for in the EPA's analysis. Commenter says, this winter has given the industry a glimpse of what can happen to the generation industry if the number of coal-fired power plants continues to decrease. Commenter says, by forcing new generation towards natural gas, the EPA is putting the U.S. electric generation at the mercy of a natural gas market that is sure to see more price volatility and more pipeline capacity issues. Commenter says, with issues such as price volatility and lack of capacity, the exorbitant costs will be felt less by energy producers, but rather by customers and the U.S. economy as a whole as energy bills increase.
Commenter 10043 says, it is also worth noting that the electric utility sector has reduced CO2 emissions by 11 percent since 2006. Commenter says, this decrease has occurred without federal CO2 regulations and stands in sharp contrast to the CO2 emissions that are increasing in Germany, Canada, Australia, Japan, Venezuela, India, China, and Russia. Commenter urges the EPA to recognize what the U.S. electric utility industry has already done to reduce emissions and issue a final rule that ensures the continued use of both coal and natural gas for new generation, without the reliability and cost concerns likely to prevail under the proposed rule.
Commenter 10097 states, this rule effectively limits new generation to natural gas, and in doing so, is at odds with good energy policy. Commenter recognizes that natural gas electric generation is playing an increasingly larger role in supplying power to the electric grid. Commenter says, common sense and experience with the nation's energy use and energy policies dictates, however, that we should not enact regulations that have the effect of virtually eliminating coal for future electric generation and that leave the nation with natural gas as the sole fossil- fuel choice for our basic generation requirements.
Commenter 10097 states, historically, EIA has a poor track record of projecting natural gas prices and as noted in the RIA.  Commenter does not fault EIA for its failures to accurately predict future natural gas prices. Commenter says, such an endeavor is obviously difficult and wrought with uncertainties as clearly evidenced by past future projection failures. But Commenter does question the EPA's rationality to proposal a rule that banks on one fossil-fuel, natural gas, to supply all future base-load electricity generation, especially considering the price and availability uncertainties. Commenters (9407, 10097) say, moreover, the risk of overreliance on natural gas is significantly enhanced because the cost of electricity generated by natural gas is principally driven by the cost of the fuel itself. Commenters say, additionally on-site natural gas storage capacity at electric generation sites is limited at best and nonexistent at most sites. Commenters say, as we have recently witnessed, hurricanes and other inclement weather including prolonged cold snaps as with this most recent winter can significantly affect natural gas price and availability.
Commenter 8024 states, while the President has advocated for an "all of the above" energy policy, the proposed rule limits the nation's electric generation options regardless of future changes in energy markets. Commenter says, there are too many uncertainties about the future price of natural gas to justify a rule that would prevent future construction of economic coal generation facilities. Commenter says, removing new coal as a competitive generation option would largely eliminate inter-fuel competition in the electric generation market. 
Commenter 10662 states, EPA's proposal will result in increased energy costs for consumers. Commenter says, the extreme volatility in natural gas pricing leads to questions regarding the validity of forecasts, which extend to 2020 and beyond, and are based on low initial prices. Commenter says, multiple natural gas price trajectories should be examined in conjunction with the cost analysis for the rule. Commenter says, EPA should also examine how a move to gas liquefaction and export within the United States or Canada has the potential to drive up domestic natural gas prices to levels seen internationally. Commenter says, EPA's IPM model does not take into account the development of these facilities. Commenter says, EPA's economic modeling to date has not adequately assessed the impacts of the final MATS rule and other pending regulations, which will lead to the retirement of many coal-fired generating units further increasing the demand for natural gas. Commenter says, the associated reduction in coal use will reduce coal prices, making coal-fired generation more viable economically.  
Commenter 8032 states, as demonstrated by years of history and the recent cold snaps, natural gas prices are volatile and spike even during shorter term weather events which has an immediate adverse effect on consumer electric bills. Commenter says, coal and its stable price is a long term hedge against natural gas volatility and is critical if we are to continue to provide affordable electricity. Commenter says, coal generally is stored in significant quantities at the plant site, providing reliability during supply disruptions due to weather and other events that often do disrupt natural gas supplies. Commenter says, coal units allow customer pricing to stay relatively constant which will be given up if the entire fleet is natural gas.
EPA disagrees. We repeat that the base case for the IPM modelling accounts for the effects of the finalized MATS and CSAPR rules, New Source Review settlements and state rules through 2014 impacting sulfur dioxide (SO2), NOx, directly emitted particulate matter and CO2, and final actions the EPA has taken to implement the Regional Haze Rule. It also includes the Cooling Water Intakes (316(b)) Rule and the Disposal of Coal Combustion Residuals from Electric Utilities Rule (CCR).   See RIA at 4-7.
Adverse effects on reliability and prices due to less diverse generation mix
Commenters (9201, 9397) provide comment on adverse effects on reliability and affordability due to a less diverse generation mix.
 
Commenter 9201 states it is very difficult to follow EPA's final reason for not identifying CCS as BSER for NGCC power plants---"the adverse effects on national electricity prices, electricity supply and the structure of the power sector" -- because all of these considerations bear equal weight in any finding for coal-fired EGUs. Commenter says, to begin with, EPA's concerns about adverse effect on electricity prices, electricity supplies and the structure of the power sector would be obviated with a finding that CCS is not BSER for any EGU (coal or natural gas). Commenter says if EPA is so confident in its forecast that few if any new coal-fired EGUs will be built if EPA does not require that coal-fired EGUs install CCS, then EPA's concerns about CO2 emissions from such units are unfounded, and there is no reason for EPA to promulgate the proposed rule. Commenter add, moreover, even if new, higher-efficiency SCPC or IGCC plants are built without CCS, those units would have CO2 emissions substantially lower than the older, less efficient subcritical plants they would replace.
Commenter 9201 states ironically, while EPA professes to be concerned about higher electricity prices and the effects on supply that would result from requiring CCS for gas-fired units, it does not venture any discussion about the adverse effects on prices and reliability that are almost certain to result from the less diverse generation mix that will be the consequence of requiring CCS for coal-fired units but not gas-fired ones. Commenter says, instead, EPA states that it remains concerned that, absent a CCS requirement for coal-fired units, additional coal plants will not be retired. Commenter says nowhere does EPA acknowledge that additional coal plant retirements will lead to adverse effects on the reliability of the grid and to increases in the price of electricity and natural gas as the nation is denied the benefits of lower-emission coal plants that will moderate and offset any increases in natural gas prices, as happened this past winter. Commenter says, in short, any concerns about the adverse impacts on supply and prices are of EPA's own making. Commenter says they are the result of a poorly-thought-out combination of power plant rules that have forced the accelerated retirement of base load coal plants and that effectively bar the construction of new, higher efficiency plants that would maintain fuel diversity and supply security. Commenter says, in the end, EPA has it backwards. Commenter says it is not a finding that CCS is BSER for NGCC that presents the greatest threats of price increases and supply constraints it now uses to eschew such a finding. Commenter says, rather, it is the agency's unreasoned and unsupported finding that CCS is BSER for new coal-fired EGUs that is the greater source of these threats.
Commenter 9201 states the system performance this winter clearly demonstrates the need and value of a diverse grid with coal base load as its backbone. Commenter says coal-fired plant availability far exceeded gas-fired plant, wind and solar availability and provided much needed system stability and reliability. Commenter says, as John Sturm of the Alliance for Cooperative Energy Services informed FERC during its recent technical conference on winter grid performance, "The unreliability of gas, wind and solar provided the lesson that fuel diversity is needed for reliability as well as for other policy reasons." Commenter says, days later, FERC Commissioner Moeller informed the Senate Energy and Natural Resources Committee that:
"Our latest winter exposed an increasingly fragile balance of supply and demand in many areas. Prices at times were extraordinarily high. The experience of this winter strongly suggests that parts of the nation's bulk power system are in more precarious situation than I had feared in years past." 
Commenter 9201 states at the same hearing, Nick Akins, Chairman & CEO, American Electric Power, testified that the "weather events experienced this winter provided an early warning about serous issues with electric supply and reliability." Commenter says, Mr. Akins noted that 89 percent of the coal capacity AEP will retire in 2015 due to EPA's MATS rule was called upon to meet electricity demand this winter. Commenter says, Mr. Akins warned that this reliability concern is imminent and EPA's GHG NSPS could make matters worse. Commenter says, Anthony Alexander, CEO, First Energy, recently commented that EPA rules will lead to less reliable service over time and that the EPA NSPS rules for power plants could have an impact similar to the UMATs rules that have brought the electric grid to the edge. 
Commenter 9397 states, if regulations such as the 111 (b) proposal start taking fuel options off the table, energy prices will become more volatile, cost will increase and reliability will be threatened.
Commenter 9731 opposes any efforts by EPA that would increase the costs of using natural gas in electric generating units. Commenter says, the natural gas renaissance in the United States will result in America having the lowest long-term natural gas prices of any industrial nation and as a result, the United States has a built-in price advantage compared to our competitors. Commenter says, the abundance of affordable natural gas in the United States also allows the opportunity for the American economy to utilize natural gas for greater electricity generation. Commenter says, in addition to the economic benefits of affordable electricity, power generation from natural gas has fewer environmental emissions than other fuel sources.  
Commenter 9497 states, Mississippi's concerns specific to fuel diversity are related to limits on potential renewable generation due to its climate and geography. Commenter says, the state now relies increasingly on natural-gas-fired power plants and on existing nuclear capacity but has several incentives and initiatives to promote commercial and residential energy efficiency and renewables.  
EPA disagrees.  See previous response.
 
Regarding not selecting CCS as BSER for NGCC, see preamble section IX.C.4.  EPA disagrees with this comment.  As EPA has emphasized in response to previous comments, this rule does not constitute a moving away from energy diversity needed for responsible policy choices, and commenters are wrong to assert historical trends or recent reliability issues have negative implications for the promulgation of this rule.  As we make clear in the TSD in the docket for this rule, "Trends in the Structure of Electric Power Sector Limiting Amount of New Coal", the trends away from coal have been occurring for some time; modeling from EPA and independently from EIA confirms that this trend can be expected to continue in the absence of this rule. The presence of this rule will not alter this basic finding.  These basic finding hold regardless of the events from recent winters, since the fuel mix will remain diverse both without the rule and with it.  As a result, EPA does not believe there will be adverse impacts on reliability.
Proposed rule will result in a higher cost, less stable, and more risk prone, electric generation and distribution system
Commenters (9602, 10039, 10048)  state that the rule will result in a higher cost, less stable, and more risk-prone electric generation and distribution system.
Commenter 9602 states, with this proposed rule, the EPA, in effect, bans new coal plants, and in doing so takes an affordable, stable and abundant electric generating resource off the table, without adequate evaluation of the availability and costs of replacement generation.  Commenter says, in doing so, the EPA introduces unprecedented levels of risk into the electric generation system that threaten costly and dangerous future shortages and potential rolling blackouts in certain regions of the country.
Commenter 10039 believes the EPA's proposed rule is intended to, and will have the net effect of, preventing the construction of new coal fired electric generating units. Commenter says, the EPA states in the proposed rule that it believes the rule will have little effect because utilities do not plan on building new coal fired generation. Commenter says, the EPA fails to acknowledge that utilities understand the adverse regulatory climate surrounding coal use due largely to the number of recently promulgated and soon to be promulgated rules directed at coal fired electric utilities, including CAIR/CSAPR, MATs, EGU GHG NSPS, CWA 316a, CWA 316b, and coal ash/solid waste regulations. Commenter says, it is this suite of rules which the utility industry believes are aimed at reducing US reliance on coal generation by regulating coal fired generation out of business. Commenter says, it is therefore self-serving for the EPA to claim that this rule does not impact the EPA's models of the industry significantly because utilities have no plans to develop new coal fired generation and ignoring that this is the EPA's ultimate goal by promulgating rules which make coal fired generation inordinately expensive.
Commenter 10039 believes that over time reducing the electric system's reliance on coal fired generation will result in a higher cost, less stable, and more risk prone, electric generation and distribution system. Commenter says, for this reason, they believe the EPA needs to re-consider this proposed rule and the effect that it will have on electric system reliability over the long term.
Commenter 10039 states a more costly, less reliable electric system will undoubtedly have a negative impact on the health of Americans by increasing the cost of energy and impacting every facet of our lives. Commenter says, higher electric costs will impact the ability of people to pay for heating and cooling, resulting in adverse effects on health, including increased hospitalizations and premature deaths. Commenter says, unreliable electric delivery can impact the operation of health care delivery organizations. Commenter says, the negative impacts of higher electricity costs as well as a less reliable electric delivery system on non-air quality health and energy in this country should be considered by the EPA. 
Commenter 10039 believes the EPA either ignores or misunderstands the vital function that coal plays in the ability of utilities to provide a low cost, reliable, and stable electricity supply. Commenter says, unlike natural gas, unlike sunlight and unlike the wind, coal can be stockpiled. Commenter says, because utilities can stockpile coal, they are not as vulnerable to large fluctuations in the cost of coal supply making coal fired generation economically stable. Commenter says, but stockpiling coal has a more important function from an electric supply perspective. Commenter says it gives utilities the ability to provide electricity to the electric grid even in the event of a disruption in the supply of fuel. Commenter says this was very important during the development of the electric grid and remains an important factor today given the geopolitical climate and the known risk of terrorism attacks on the electric grid. Commenter says the EPA needs to understand, and accommodate in this and any proposed rules dealing with electric utilities, that forcing change to the electric grid through regulation of electric generating units can result in an electric system which is more vulnerable to disruption.
Commenter 10039 states it is widely understood that the electric grid is vitally important to the economic stability of the United States. Commenter says, for this reason, short term and long term disruptions of the electric supply are considered to be a prime objective of terrorist organizations. Commenter says, coal fired generation is a fundamental hedge against electric supply disruption because it is nearly impossible to disrupt coal fuel supplies for periods longer than on-site coal stockpiles can reliably meet generation needs.
Commenter 10039 states natural gas, on the other hand, is not and cannot be safely, reliably stockpiled at the point of generation. Commenter says, natural gas must be piped into generating facilities continuously at large quantities from long distances. Commenter says, disruption of natural gas supplies either because of pipeline events such as terrorism or because of supply restrictions due to heavy demand, as occurred in late 2013 and early 2014, results in the unavailability of natural gas electric generation. 
Commenter 10039 states, in a future where natural gas is the source of base load electric generation, electric supply disruption will be as simple as disrupting the pipeline supply of natural gas. Commenter says, eliminating a single pipeline either by terrorist attack, pipeline failure, or natural event (earthquake), could result in the shutdown of a significant portion of the electric grid in this country for a significant period of time in the absence of coal fired base load generation. Commenter says, this disruptive effect has been observed in areas of the Middle East which largely rely on fuel pipelines to supply fuel to electric generating units. Commenter says, terrorist disruption of a pipeline would result in weeks of electric distribution system downtime should the US become overly reliant on NG as the source of base load power generation.
Commenter 10048 echoes this concern, saying that infrastructure security is a concern in the transport of natural gas.  Commenter says, if a major transmission pipeline becomes compromised or unavailable, it could result in detrimental impacts to electricity reliability in a given area.  Commenter 10048 states that the EPA failed to appropriately consider these challenges in its analysis. 
Commenter 10039 states this is a significant risk which must be taken into account in a rule that by its own admission can and will result in a wholesale change in the mix of base load generation units over the long term. Commenter says, this rule obscures the fact that it will result in a change to the electric generating industry from a reliance on coal for intermediate and base load generation to a greater reliance on natural gas for intermediate and base load generation.
Commenter 10039 states the EPA's assertions that utilities prefer fuel diversity which can be met with nuclear, biomass and geothermal power ignores the reality that these forms of generation cannot and will not be able to replace coal supplied generation. [A utility's preference for fuel diversity is an economic preference since fuel diversity leads to least cost generation methods over the long term and limits a utility's economic risks associated with short term price spikes on individual fuels. However, utilities must plan for changes to generation mix years and even decades in advance. Construction of new generating units at even an existing facility can take up to ten years from the planning and permitting stage to the end of construction. This is a longer term view that necessitates a broad mix of generation assets.] Commenter says, fundamentally, nuclear power's share of generation has not increased since 1988 and new nuclear power projects have been limited in that time because, fundamentally, nuclear power (post Chernobyl and post Fukushima) presents too much risk at too high a capital cost. [Commenter acknowledges that US DOE has embarked on a new small modular reactor technology development program, however, at this point in time, this program has not changed the fundamentals underlying the risk involved in private investments in new nuclear power projects. Cost pressures related to low natural gas prices and low electric wholesale prices will result in a 10% decrease in available nuclear capacity by 2020 according to EIA estimates in their 2014 annual report. This is contrary to EPA's assertion that nuclear supplemented by biomass and geothermal can replace coal base load generation. See Commenter's Attachment 1.] Commenter says, biomass and geothermal power do not have the potential to replace coal supplies for intermediate or base-load generation due to lack of biomass supply and a lack of geothermal development potential.
We disagree with the commenter's statement. The EPA's modeling, conducted using the Integrated Planning Model (IPM), as well as modeling conducted by the U.S. Energy Information Administration (EIA) showed that new generating capacity built through the period of analysis would be in compliance with the standard even in the absence of the regulation. This finding held true even under a number of alternative scenarios involving significant increases in both natural gas prices and electricity demand. As a result, the EPA projects that  there will be negligible costs, benefits, or energy impacts (including changes to natural gas prices) associated with the rule in the period of analysis.
The proposed rule will leave the nation's electricity supply less diverse, less reliable and more expensive
Commenters (9190, 9590, 9725, 10050, 10552, 10680, 10880, 10928, 10974, 10975, 11062, 11063) state, the proposal will leave the nation's electricity supply less diverse, less reliable and more expensive while providing no environmental benefits.
Commenters (9190, 9590, 9725, 10050, 10552, 10680, 10974, 10975, 11062, 11063) state, the EPA's proposal effectively bars the construction of new higher efficiency coal base load power plants that are needed to maintain a diverse, reliable and affordable electricity supply. Commenters say, the centrality of coal based electricity to the reliability and affordability of the nation's electricity supply is beyond dispute. Commenters say, over the past ten years, coal based electricity generation has supplied more than 45 percent of the nation's electricity supply. Commenters say, currently, 25 percent of the nation's base load power generation capacity (coal, natural gas and nuclear) is 40 years or older and in another decade that will reach almost 50 percent. Commenters say, the Department of Energy's Energy Information Administration forecasts that 60,000 megawatts of coal based load power capacity will close over the next several years principally in response to the EPA's recent mercury and air toxic regulations. Commenters say, to maintain a diverse, reliable and affordable electricity grid, new higher efficiency coal units will be required to replace the retiring older coal, natural gas and nuclear electricity generation plants.
Commenters (9190, 9590, 10050, 10552, 10680, 10880, 10928, 10974, 10975, 11062, 11063) state, the importance of supply diversity to the reliability and affordability of electricity is readily apparent. Commenters state, the proposed standard will also lead to more volatile energy costs for businesses and households. American businesses will be less competitive, high-wage jobs destroyed and families forced to pay more to heat and light their homes. Commenters note, Phillip Moeller, Commissioner, Federal Energy Regulatory Commission (FERC), recently testified that "the power grid is now already at the limit" and the "nation's bulk power system is in a more precarious situation than [he] had feared in years past." Commenters note, Michael Kormos, PJM Interconnection, recently advised FERC that "because less expensive coal generation is retiring and being replaced by other potential high energy cost resources, energy prices could become more volatile due to the increasing reliance on natural gas for electricity generation." Commenter 10880 adds, that Nick Akins, CEO of American Electric Power (AEP), also informed Congress that EPA rules have impaired the reliability of the electric grid and "the next cannon ball we see coming at us may not be one we can dodge."  Commenters say, indeed, natural gas prices have more than doubled since their low of $1.82 mm/BTU in April of 2012. Commenters say, this past winter, natural gas prices in some regions reached record highs with mid-points around $40 mm/BTU and bids as high as $100 mm/BTU. Commenters say, daily average power pricing followed swinging wildly from $40 to $800 MWh. Commenters state, greater use of natural gas is partly due to increased supply making it more competitive. Commenters say, however, federal regulations like Utility MACT have led to the closure of a significant number of coal-fired power plants, thereby forcing natural gas generation to pick up the slack. Commenters say, the result is less energy diversity and an electrical grid that is more vulnerable to price spikes during extreme temperatures. Commenters say, in many regions of the country, households depend on natural gas for heat. Commenters say, when temperatures drop, demand for natural gas increases for all consumers including households, commercial buildings and the electric power sector. Commenters say, natural gas supplies can be temporarily strained, particularly if there is insufficient pipeline capacity to meet the spike in demand. Commenters say, during the 2014 polar vortex, some regions of the country came perilously close to demand for natural gas exceeding supply which would have led to interruptions of electricity service.
Commenter (10680) says, unfortunately, this situation likely will only get worse. Commenter (10880) states, Akins further testified that 89 percent of the coal capacity AEP will retire in 2015 due to EPA's Mercury and Air Toxics Standards (MATS) rule was called upon to meet electricity demand this winter. Commenter (10680) says, this situation is a clear-cut example of how the EPA's proposed GHG rule for new power plants can and likely will threaten the reliability and affordability of electricity in this country. Commenters (9190, 10552, 10680, 10974, 10975, 11062, 11063) say, in this regard, EPA's analysis and assumptions for electricity and natural gas pricing are inadequate and unrealistic.
Commenters (9590, 9725, 10050, 10552, 10680, 10974, 10975, 11062, 11063) state, the EPA fails entirely to consider the probability of significant price increases. Commenters say, turning a blind eye toward the inevitable is irresponsible and a costly gamble with the nation's energy future. Commenters say, coal serves primarily the power generation market, while natural gas serves many needs including power generation, residential heating, commercial feedstock for manufacturers, transportation and, in the near future, the liquefied natural gas export market. Commenters say, the EPA's NSPS policies will have a profound effect upon not only the domestic electricity markets but also many sectors of our economy that rely upon natural gas. Commenters say, as the Department of Energy's NETL has warned "policies that encourage the use of natural gas to substitute for coal in power generation could very well lead to spectacular price increases for households and industry." Commenters say, indeed, according to NETL, coal-based electricity restrained the price of electricity and prevented the price of natural gas from matching the rise in the price of oil. Commenters say, the EPA's NSPS proposal will change all of that-and for the worse. Commenters say, nothing in EPA's proposal demonstrates that the agency has performed a reasonable assessment of the impacts of this rule upon the vast number of economic sectors that rely upon reliable and competitively priced electricity and natural gas.
Commenter 10050 states, past efforts by the government to establish preference for various fuels have been followed by emergency action to relax those restrictions when prices have spiked, resulting in substantial energy distortions. Efforts to move the industry to gas in the past have been followed by the energy shortage and emergency orders to convert plants back to coal.
Commenter 10880 states, the proposed rule does not credibly nor adequately project the cost of electricity if the rule is implemented as proposed. Commenter goes on, nor does it take into account the effect on lower income families. Commenter says, due to this proposal, almost half of American households will devote an estimated 20 percent of their after-tax income to energy. Commenter says, in short, rising energy costs impose a substantial burden on most Americans, especially those whose incomes fall below $50,000 in earnings.
Commenters (10963, 11062, 11063) state, coal currently comprises over 40% of this country's electricity needs and has been a major component of the electrical grid for over 100 years. Commenters say, despite this, the proposed NSPS effectively ban the new construction of coal-fired plants and overlook an abundant and dependable resource whose use is growing in every country except our own. Commenters say, we cannot afford to continue to ignore the position coal maintains in our nation's energy portfolio. Commenters say, to do so is to trade a strength for a weakness that will ultimately come at the expense of our nation's economy and grid reliability.
EPA disagrees.  The rule is not expected to change the expectation that coal will not be built in the future.  Coal will continue to be a major source of power generation in the future with or without this rule.  Moreover, as new sources, natural gas combined cycle units are highly effective for preserving reliability. The EPA's modeling, conducted using the Integrated Planning Model (IPM), as well as modeling conducted by the U.S. Energy Information Administration (EIA) showed that new generating capacity built through the period of analysis would be in compliance with the standard even in the absence of the regulation. This finding held true even under a number of alternative scenarios. As a result, the EPA projected there would be negligible costs, benefits, or energy impacts associated with the rule in the period of analysis. See RIA Chapter 4.
Diminished fuel diversity will impair reliability and affordability 
Commenters (2470, 3176, 3360, 8957, 9597, 9774, 10104, 9497, 10788) state that diminished fuel diversity will impair reliability and affordability. 
Commenter 2470 states, the EPA's final rules should avoid compromising electric system reliability and allow the maximum compliance flexibility for electric utilities provided for under the CAA. Commenter says, electric utilities should be given the flexibility to choose the most efficient, least-cost compliance options to meet public health and environmental goals. Commenter says, because a diversified fuel supply can enhance system reliability and significantly mitigate the effects of volatile fuel price fluctuations, extreme weather events, and unplanned plant outages, it is important that utilities are afforded the greatest possible level of flexibility in determining their generation fuel source mix when seeking to comply with relevant carbon standards.
Commenter 3176 states, the proposed rule effectively bans traditional coal-fired generating technology as a future supply option, despite the fact that this base-load technology has provided reliable, cost-effective electricity to consumers in Alabama, and nationally, for many decades. Commenter says, in so doing, the proposed rule stands to weaken the country's generation portfolio and significantly impact the future cost of electricity. Commenter says, the proposed standard may impact the reliability of our nation's electric system and, as a result, customers will be forced to pay more for a product that is less reliable.
Commenters (3360, 10104) state, the United States utilizes a variety of fuels to generate electricity: coal, natural gas, nuclear, hydropower, wind, solar, biomass, and other renewables. Commenters say, by relying on a diversity of fuels, as well as energy efficiency, American consumers and the U.S. economy are less susceptible to price shocks and market disruptions. Commenters say, our current energy mix has allowed utilities to supply affordable, baseload electricity to customers, mostly through coal-fired and nuclear facilities, while also advancing lower carbon electricity through renewables and natural gas. Commenters say, any precipitous move away from this balanced mix could have serious repercussions for the affordability and reliability of our electricity. 
Commenter 8957 states, the proposal can only impair the reliability and affordability of domestic energy supplies by diminishing the diversity of electricity generation sources, both in terms of fuel type and technology, which we rely upon to maintain the energy security of the United States. Commenter says, the proposed rule acts as a de facto mandate from EPA that forces utilities to switch from coal-fired generation to natural gas in the future. Commenter says, the proposal can be construed as an attempt by EPA to pick "winners and losers" in the market place. Commenter says, it is not appropriate or reasonable for an environmental agency to make these types of policy judgments. Commenter concludes, this de facto natural gas mandate may leave U.S. consumers and businesses exposed to less reliable, more expensive, and more volatile electric generation sources in the future.
Commenter 9597 states, fuel diversity ensures that market volatility or supply in one sector can be dampened by utilizing EGUs with different fuel capabilities. Commenter says, put another way, the customers of a generation fleet that overly relies on one fuel type, will undoubtedly experience periodic swings in energy costs. Commenter says, this proposal will further these types of unpredictable and expensive cost swings for electricity customers.
Commenter 9774 expresses a similar concern, highlighting their very significant concern that the NSPS will effectively prohibit siting new coal-fired generation in Wisconsin and within the utility sector as a whole. Commenter states, this impact will result in greater reliance on natural gas fired generation, potential electric reliability issues, added costs, and inequity among states. 
Commenter 0784 states, EPA's effort to improve overall public health by reducing emission from coal-fired generation units has the potential to undermine the electric grid system. 
Commenter 9777 states, by establishing gas-fueled generation as the only cost-effective option for baseload and demand- following generation, the proposed NSPS would undermine fuel diversity and risk leaving both consumers and retail electricity providers subject to price spikes and electricity supply shortages. Commenter says, the risk of electricity supply shortages is exacerbated through an over-reliance on gas-fueled generation and unlike a coal-fueled power plant, which may store two to three weeks of fuel on-site, gas-fueled plants cannot store reserves of their fuel. Commenter says, disruptions to supply, either through shortages or pipeline failures, could result in the immediate shutdown of regional gas-fueled plants. Commenter says, although each type of power generation is subject to its own reliability risks, fuel diversity ensures that power generation companies have the best chance to continue to supply electricity during times of disruption. By materially limiting fuel diversity the proposed NSPS significantly threatens grid reliability.
Commenter 9777 states, the current spread between coal (with historically stable prices) and natural gas may close in the future, making coal-fueled generation more cost-competitive with gas-fueled generation. Commenter says, with EPA's decision to mandate a CO2 emission limitation that can only be met by a technically infeasible and expensive control technology, options to construct new baseload and demand-following plants would be limited.
Commenter 9497 states, fuel diversity helps ensure reliability and price stability in electric supply, constraints in fuel availability and spikes in fuel prices, related to disruptions in physical production and distribution as well as impacts from regulatory changes, can seriously affect electric companies and customers. Commenter says, diversification of the fuel mix used for generation can help protect against supply crises and temper the exposure of ratepayers and businesses to price volatility.
Commenter 9723 states, EPA regulations should not limit future fuel diversity, which ensures reliable, least-cost electricity. Commenter says, the coal-fired EGU standard in the proposal effectively precludes the building of new coal-based plants and would put the nation at risk of over-reliance on a single fuel source, natural gas. Commenter says, EPA's proposed emission limits for new EGUs precludes coal-based units from playing a role in the power sector's new generation option mix going forward unless carbon capture and storage (CCS), which is not commercially or technically feasible today for EGUs, is employed.  
Commenter 10788 states, fuel diversity is important both to current operations and future generation resource planning. Commenter says, the proposed rule effectively eliminates the ability to consider new coal-fired EGUs for future generation which impacts the ability to provide reliable and affordable services to members. Commenter says, the ability to choose from a suite of fuel options during resource planning retains fleet flexibility and reliability and also ensure that economic and efficient electricity is provided to members. 
EPA disagrees with this comment.  There is no basis for the root assumption of all of these comments that the final standard of performance in this rule will limit future fuel diversity.  As EPA has emphasized in response to previous comments, this rule does not constitute a moving away from energy diversity needed for responsible policy choices, and commenters are wrong to assert historical trends or recent reliability issues have negative implications for the promulgation of this rule.  As we make clear in the TSD in the docket for this rule, "Trends in the Structure of Electric Power Sector Limiting Amount of New Coal", the trends away from coal have been occurring for some time and are obviously not caused by the standards adopted here; modeling from EPA and independently from EIA confirms that this trend can be expected to continue in the absence of this rule. The presence of this rule will not alter this basic finding.  

These basic finding hold even in light of the events from recent winters, since the fuel mix will remain diverse both without the rule and with it.  As a result, EPA does not believe there will be adverse impacts on reliability.
Proposed rule will increase electricity costs and impact reliability
Commenters (0840, 8966) believe the proposed rule will increase electricity costs and impact reliability. 
Commenter 0840 states, the EPA is not required to set an existing NSPS for EGUs. Commenter says, however, the agency is going forward with one at the behest of President Obama, even though such a standard could result in immediate harm to electric customers. Commenter believes that regulating CO2 from existing power plants could significantly increase electricity costs and hurt residential, commercial, and industrial customers, as well as impact reliability in certain parts of the country.
Commenter 8966 states that ratification of the rule will cause additional harm to the availability of affordable electricity. Commenter says, the wholesale closure of hundreds of coal-fired power plants without an equal level of replacement construction will amount to the loss of tens of GW available to the electricity grid, and has been projected by several regional electric reliability corporations to seriously threaten grid reliability and continuous service to consumers. 
Commenter 8966 says, further, any new coal plant implementing CCS will be required to increase the cost of electricity by 65% over that from a most advanced, ultra-supercritical coal-fired plant, according to DOE's NETL. Commenter says, the lack of availability of coal-based power is likely to cause dramatic price spikes during high demand seasons. Commenter says, for instance, in January 2014, PJM Interconnection, a regional grid operator, requested permission to exceed a $1,000 per MWh price cap, in comparison to the $42 per MWh average rate. Commenter says these price spikes ultimately translate to higher energy costs for consumers, as well as higher costs of goods and services, particularly hurting the poor.
Commenter 9777 states, the efficacy of these projects to reliably generate power and reduce U.S. CO2 emissions is unknown at this time and current cost estimates put these plants well outside the bounds of conventional financing. Commenter says, while it is possible that rising gas prices could create an economic environment favorable to construction of coal-fueled EGUs, it is unlikely that gas prices could ever get high enough to justify the costs of the types of projects cited by EPA. 
Commenter 10086 disagrees with EPA's conclusion that the proposal if finalized will have no cost. Commenter says, the resulting costs of the proposal will be substantial for electric consumers and that EPA should rethink the NSPS. 
The EPA disagrees with commenters' statements that the regulation will cause economic harm. EPA's modeling, conducted using the Integrated Planning Model (IPM), as well as modeling conducted by the U.S. Energy Information Administration (EIA) showed that new generating capacity built through the period of analysis would be in compliance with the standard even in the baseline scenario and, as a result, the rule would not lead to changes in behavior. This finding held true even under a number of alternative scenarios, including scenarios developed by EIA that reflect economic conditions most favorable to the development of new coal. As a result, the EPA projected there would be negligible costs, benefits, energy impacts (including changes to electricity prices), employment impacts, or economic impacts associated with the rule in the period of analysis. (See Chapter 4 of the RIA.) The baseline for this analysis included existing regulations, so this conclusion takes into account impacts of those actions. In addition, in Chapter 5 of the RIA, EPA presents an analysis of the potential costs and benefits of these standards under a range of natural gas prices. It is only when levelized natural gas prices reach levels not seen in EIA data going back to 1996 that an NGCC unit would become less economic than a non-compliant coal unit.
Proposed rule will harm affordability, reliability, or jobs
Commenter 1510 states, the rules will make our nation's energy less reliable and less affordable, impacting mine, power plant, factory and other workers, their families and their communities, and resulting in serious adverse impacts on their health and well-being. Commenter says, their nutrition will suffer; they will battle with sleep deprivation and higher incidences of depression; they will face more prevalent alcohol, drug, spouse and child abuse, higher suicide rates, more heart attacks and strokes, and lower life expectancies. Commenter says, this means every life that EPA claims its rules will improve - by supposedly preventing climate change- will be made worse by EPA's own rules. Commenter says, every life that EPA says will be saved by its costly, job-killing carbon dioxide regulations will be offset by lives shortened or lost by those rules.
Commenter 1681 is concerned about the EPA's carbon regulations because of their negative impact on the use of coal to produce affordable and reliable electricity, and for its negative impact on direct and indirect jobs of many fine hard working American men and women involved in the coal industry. Commenter says, first, the EPA's carbon regulations should do no harm. Commenter says, carbon regulations should not interfere with affordable electricity prices, reliable electricity supplies, or eliminate well-paying American jobs, especially in states that rely on coal. Commenter says, finally, the EPA should remove all regulatory barriers to efficiency improvements at existing coal-fueled power plants. Commenter says, efficiency improvements are a cost-effective way to reduce emissions, while maintaining affordable and reliable operations.
Commenter 2658 states, EPA should ensure that any greenhouse gas regulations are cost effective, attainable and protect American jobs and the economy. 
Commenter 2658 states, in addition to the direct electricity affordability costs of such a situation, over time the increasing lack of base load electricity diversity will threaten reliability and unnecessarily limit risk management tools available to power generators. Commenter says, forcing out a specific fuel source from the electricity generating mix will reduce the reliability of the electricity supply and carry with it real costs both economic and societal. Commenter says, Federal Energy Regulatory Commission (FERC) Commissioner Philip Moeller recently said he expects people will be "panicked" about grid reliability in 2015 due to coal plant shutdowns. Commenter says, EPA should work with FERC and other appropriate experts to study how the proposed rule's ban on new coal-fired power generation could impact electricity affordability and reliability over the long-term. Commenter says, the agency should also examine additional plausible economic scenarios to better understand the potential costs of the rule in the event its forecasts are not accurate. 
Commenter 2658 states, taking a major energy source off the table with respect to meeting future electricity is risky and threatens affordability and reliability while reducing base-load electricity diversity. Commenter says, EPA should work with FERC and other experts to analyze the potential long-term impacts of the rule on reliability and affordability. 
Commenter 0784 states, while the EPA statutory charge does not require it to consider grid reliability and customer costs in its deliberations, coordinating overall policy development and implementation schedules with the FERC and DOE, to minimize direct and indirect energy and health care costs, would seem the prudent and responsible course of action. Commenter says, EPA should consider the impact of renewable generation intermittency and high voltage transmission line inadequacies while proposing the new plant CO2 emission levels.
Commenter 10555 states, EPA's proposed rule threatens the nation's competitiveness and drives jobs to other countries with increased GHG emissions. Commenter says, the competitive business climate in many states will be diminished without the availability of affordable energy. 
Commenter 10555 states, it is vital that the U.S. utilizes an all-of-the-above energy strategy because energy supply diversity keeps energy costs reasonable and ensures steady and reliable energy for industries and homes. Commenter says, with recent technological advances and domestic resource availability, the U.S. is at a competitive advantage when it comes to energy prices and reliability. Commenter says, the proposed regulation threatens to remove this competitive advantage as energy prices become more volatile and reliability diminishes. Commenter says, any reduction in U.S. emissions created by this rule will not only be offset by increasing emissions from emerging economies, but it is likely to result in a net increase in global emissions. Commenter says, a more effective policy would be to promote on-shoring of jobs and production from inefficient carbon intense economies to the efficient U.S. economy.
Commenter 10555 states, businesses and citizens have already incurred substantial burdens through legal mandates on electric generation facilities, including those resulting from legal settlements, fuel switching, forced retirements, pollution controls, renewable portfolio standards, and energy efficiency programs. Commenter says, further imposition of mandates is neither justified nor acceptable.
The EPA disagrees with commenters' statements that the regulation will cause economic or employment impacts. Additionally, the regulation is not expected to cause reliability impacts or leakage of jobs or industry to other countries. EPA's modeling, conducted using the Integrated Planning Model (IPM), as well as modeling conducted by the U.S. Energy Information Administration (EIA) showed that new generating capacity built through the period of analysis would be in compliance with the standard even in the baseline scenario and, as a result, the rule would not lead to changes in behavior. This finding held true even under a number of alternative scenarios, including scenarios developed by EIA that are most favorable for development of non-compliant coal. As a result, the EPA projected there would be negligible costs, benefits, energy impacts (including changes to electricity prices), employment impacts, or economic impacts associated with the rule in the period of analysis. (See Chapter 4 of the RIA.) In Chapter 5 of the RIA, the EPA presents an analysis of the potential costs and benefits of these standards under a range of natural gas prices. It is only when levelized gas prices reach levels not observed in EIA data going back to 1996 that an NGCC unit would become relatively more expensive than a non-compliant coal unit. The baseline for this analysis included existing regulations impacting the power sector, so this conclusion takes into account impacts of those actions.
CCS and affordability and reliability
Commenters (4710, 7433, 7977, 8971, 9408, 9597, 10036, 10051, 10089, 10100, 10664, 9774) are concerned about the impact of CCS on affordability and reliability.
Commenter 4710 states, instead of mandating technology that is not commercially-available, the final NSPS rule needs to recognize the DOE timeline and allow for commercially-available technology to reduce CO2 emissions and allow utilities the flexibility to continue to innovate and achieve greater efficiency, as well as allow commercial CCS technology to "come into its own," all while utilizing our abundant, affordable, and reliable coal reserves. Commenter says, failure to do so will greatly increase electricity prices, increase reliance on natural gas and threaten the reliability of the grid by diminishing fuel choices to generate stable, baseload electricity, as well as cause the loss of thousands of jobs in the coal-mining and manufacturing sectors.
Commenter 7433 states,  making coal uneconomic by requiring CCS and expecting rate-payer or shareholder cost recovery makes it impossible to ensure base load reliability. Commenter is concerned that without adequate funding and/or demonstrated economic viability, CCS technology is not an economically viable means for a coal-fired or pet coke-fired unit to comply with the standard; nor is it necessary. Commenter says, by eliminating coal from the energy generation mix the proposed rule stands to jeopardize grid reliability, public safety, and affordability of utility service. Commenter urges the EPA to accept standards that will allow for the development of supercritical coal plant configurations and options other than gas generation alone. Commenter says, by accepting these standards, it would accomplish the EPA's goal of lower carbon emissions but grant regions currently reliant on coal generation cost-effective opportunities to ensure overall system reliability.
Commenter 7977 states, estimates indicate that the addition of CCS to either an NGCC or USCPC facility would increase cost per kWh by 40 percent to 58 percent respectively.   Commenter says, partial CCS with EOR would result in a 13 percent increase in the cost of electricity from a baseline of zero CCS, according to the Clean Air Act Task Force. Commenter says, by establishing partial CCS as the BSER for new coal-fired power plants, the proposed rule would have an adverse effect on the price of electricity in Kentucky and many other states.
Commenter 8971 states, the EPA states that the fact that costs can be passed on to consumers is a factor in determining whether the costs of a regulation are excessive. 79 Fed. Reg. 1464. Commenter says, while this fact is unlikely to make it into the Obama Administration's talking points, they believe that is fundamentally specious to justify a major rulemaking on the basis that the costs of said rulemaking can easily be passed on to the American consumers and the businesses that employ them. 
Commenter 10036 states, the reliability of a CCS system could be affected by problems arising in each CCS process. Commenter says, because carbon capture, compression and transportation, and storage have not been integrated on a power plant, it is unknown how the three processes will interact. Commenter says, for example, it is unknown how problems (e.g., forced outages) at the capture unit will affect the CO2 injection and storage operations. Commenter says, if the capture unit goes down and the CO2 injection rate fluctuates or stops, there could be resulting impacts to the geologic formation. Commenter says, intermittent flow of CO2 into the formation could, in the short term, affect the formation's ability to receive and store the CO2 stream, thus reducing the storage volume while the power plant recovers from shutdown. Commenter says, any issue at the injection site, or along the pipeline, would also directly impact the power plant's ability to operate and to serve its customers while remaining in compliance with the NSPS emission limit. Commenter says, these problems tend to be amplified if the generator relies on third parties to transport, receive and store CO2. Commenter says, together, these concerns can impact the reliability of all major subsystems involved - the power plant, the pipeline, and CO2 storage. Commenter says, the EPA must address these concerns before requiring use of CCS on all new coal fueled EGUs.
Commenter 10051 has concern about the increased cost that will be passed onto industrial consumers as a result of the proposed rule and the use of CCS. Commenter says, implementation of the proposed rule will lead to higher electricity costs, because any new coal-fired power plant will be required to use CCS to control GHG emissions. Commenter says, the EPA acknowledges in the proposed rule that CCS will have higher costs in geographic areas of the country where enhanced oil recovery (EOR) is not practicably available which may tilt the economics against new coal-fired construction. 79 Fed. Reg. 1482. Commenter says, additionally, the EPA indicates that CCS "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. Commenter says, the energy penalty occurs because the CO2 capture process uses some of the energy (e.g., electricity, steam, heat) produced from the plant." 79 Fed. Reg. 1472. 
Commenter 10089 states, any costs that utilities would incur in deploying CCS projects would be borne by consumers. Commenter says, the risk of unjustly burdening ratepayers with these costs warrants scrupulous deliberation regarding whether and how CCS can be incorporated in the construction of new power plants in a cost-effective manner. 
Commenter 10100 states, the disincentives to construction of new coal-fired EGUs could impact reliability and prevent states from diversifying their energy portfolios. Commenter says, the excessive costs associated with constructing a coal-fired plant with CCS means that few, if any, merchant power companies or regulated electric utilities will invest in a new coal-fired power plant with CCS. Commenter says, because the Proposed NSPS effectively bans new coal-fired generation in the absence of commercialized CCS, it creates an incentive to continue the operation of older, less efficient coal-fired EGUs rather than construction of new, more efficient units as well as increasing reliance on natural gas rather than maintenance of a more diversified energy portfolio.
Commenter 10664, states industrial operations, in particular, face serious risk with respect to CO2 control. Commenter says, flue gas separation is expensive and access to geological sequestration for smaller emitters is limited and costly. Commenter says, given the EPA's new rules for assuring ground water quality, the long-term risk to small operations is even more stifling. Commenter says, the lack of other options has driven these operations toward natural gas, with little possibility of future CO2 control. Commenter says, natural gas boilers emit less CO2 than coal per Btu, but without control, long-term CO2 release will continue unabated. Commenter says, natural gas, which has higher value uses in the production of fertilizer and in home heating, will continue to rise in price as demands increase, resulting in higher food, home heating and electricity prices. Commenter concludes, without options to mitigate CO2 emissions, the ultimate loser will be the consumer.
Commenter 0840 states, not-for-profit entities owned and controlled at the local level have their customers bear all associated costs of complying with environmental regulations and therefore cannot risk spending significant sums of money on risky or unproven technologies that could increase electric rates. 
Commenter 9422 states, only NGCC turbine units can comply with the proposed CO2 limit and that the regulation should take into account the availability of natural gas in all areas of the country. Commenter says, a detailed analysis of current natural gas availability throughout the country and the availability of geological formations that may be suitable for CCS, when it becomes available as a viable control technology, is needed before a regulation is promulgated. 
Commenter 6871 states, new coal generating plants can serve as the platforms for CCS development when second-generation technology is available at lower costs. Commenter says, data show first generation CCS technology would raise electricity costs by 80%. 
Commenter 9774 states, EPA cannot rely on natural gas fired generation in demonstrating that CCS for the coal-fired NSPS is feasible or achievable. Commenter says, EPA claims that CCS is achievable because no new coal-fired generating units will be built in the foreseeable future and that instead the industry will only build natural gas-fired generating units so CCS will not be needed. Commenter says, the NSPS must be set on what can be achieved for the coal-fired generation source category and not be based on the assumption that this generation will be replaced by natural gas. Commenter says, EPA relies on future potential conditions in the analysis in determining that the NSPS is feasible and that EPA does not consider, for example, that the cost of natural gas may rise, making the installation of coal-fired generation necessary. Commenter says, EPA further substantiates the proposed coal-fired NSPS by saying that natural gas generation can be placed anywhere that CCS is not feasible. Commenter says, in making its determination, EPA cannot make these caveats and assumptions instead it must simply evaluate whether CCS is presently available and achievable for construction of new coal-fired electric generating units where coal-fired generation is currently operating.
Commenter 9774 states, EPA's approach in assuming that all new electricity can be generated from natural gas is a dangerous precedent. Commenter says, widespread replacement of coal-fired generation with natural gas may result in an over-reliance on natural gas generation, which can affect electric reliability and cause significant added cost to the residential, commercial and industrial users of natural gas. 
The EPA's modeling, conducted using the Integrated Planning Model (IPM), as well as modeling conducted by the U.S. Energy Information Administration (EIA) showed that new generating capacity built through the period of analysis would be in compliance with the standard even in the absence of the regulation. This finding held true even under a number of alternative scenarios, including a range of natural gas prices. As a result, the EPA projected there would be negligible costs, benefits, or energy impacts associated with the rule in the period of analysis. Moreover, comments (6871, 7977) projecting price increases of 40-58% appear to be based on implementation of full CCS, which is not the basis of the standard, and are far higher than predicted increases for the final standard.  See preamble Table 8.  

Commenter 10036 questions the reliability of CCS.  The technology is performing admirably at full scale at Boundary Dam.  POWER magazine recently voted Boundary Dam its power plant of the year (Aug. 1, 2015)(available in the docket for this action).  Among the findings that supported this award:

   * When the staff I met with talked about the first CO2 capture in September, they still exuded excitement. That first, successful attempt to capture the gas -- which happened at 1 a.m., with a control room packed with onlookers -- went so smoothly that they still seem surprised. The first sale of CO2 occurred October 1.

   * On February 11, SaskPower issued a press release concerning preliminary performance data from BD3. Mike Monea, SaskPower's president of carbon capture and storage initiatives, was quoted as saying, "The project is generating vast amounts of data never before available to scientists and engineers around the world, and the numbers are very impressive."

   * Approximately 135,000 mt of CO2 had been captured between the project's official launch and February. CO2 purity was virtually 100% (4.5% better than expected), while the parasitic load was 10 MW lower than expected

   * SaskPower notes that this first-of-its-kind carbon capture plant was finished on budget; challenges associated with the existing power plant were the cause of cost overruns

See also responses on this issue in RTC 6, noting the NETL (July 2015) assessment that compression and capture technology is highly reliable.
Affordability and reliability in Alaska
Commenters (7893, 10022, 10504) comment on the proposed rule's effect on affordability and reliability in Alaska. 
Commenter 7893 states, the proposed GHG NSPS will further increase the high costs of electricity already borne by Alaskans, especially those in remote roadless villages and in the Fairbanks-Interior region of the state. Commenter says, as it stands, uncertainty associated with fuel prices and regulatory compliance costs make it difficult to provide effective solutions to reduce the cost of electricity for Alaskans. Commenter says, the proposed NSPS for GHG emissions from EGUs does not facilitate needed solutions to Alaska's high energy rates; in fact, it further inhibits development and technological improvements to the Alaskan power sector.
Commenters (7893, 10022) state, natural gas is not readily available nor is it cost effective to all parts of Alaska. Commenters say, the EPA justifies GHG NSPS based on available and inexpensive natural gas in the U.S. for power generation. Commenters say, while this may be true for utilities located in the contiguous 48 states, this is not the case for most of Alaska. Commenters say, although natural gas is currently available for heat and electric generation in the city of Anchorage and surrounding areas and some locations in the Kenai Peninsula, natural gas is either not available or uneconomic for power generation in Interior Alaska and in the remote communities/villages. 
Commenters (7893, 10022, 10504) state, requiring new EGUs in Alaska to install and operate partial CCS will constrain a utility's ability to provide affordable power. Commenters say, the EPA states that utilities can easily choose the more economical NGCC technology over solid fossil fuel-fired EGUs with partial CCS. Commenters say, this option may be more economical where cheap natural gas is available in the U.S. Commenters say, natural gas is neither cheap nor available in the Interior and remote villages of Alaska. Commenters say, fuel and fuel transport costs are the primary drivers of elevated energy prices in these areas. Commenters say, as a result, there are few economical energy options.
Commenters (7893, 10022) state, coal is the least expensive and most abundant fuel for heat and power generation in the Interior. Commenters say, utility operators have obligations to customers to provide affordable power. Commenter says, energy costs in the Interior can be lowered by replacing or building new efficient coal-fired EGUs and cogeneration plants. Commenter says, the proposed EPA rule would have the opposite effect as it would eliminate the Interior's most affordable power source. Commenter says, energy costs would increase with the requirement to install and operate partial CCS systems, with their admittedly high capital costs for installation, operation, and maintenance.
Commenter 10504 states, the GHG NSPS, as proposed, has the effect of inhibiting the acquisition of newer more efficient coal-fired generating units to replace older less efficient coal-fired technology. Commenter says, in the interior of Alaska energy costs can be lowered by replacing or building newer, more efficient, coal-fired EGUs and cogeneration plants. Commenter says, ultimately, the installation and operation of partial CCS systems would be required by new coal units to ensure compliance with the standard. Commenter says, CCS installation would not only add to the capital cost of a new EGU, but add to the cost of operation and maintenance. Commenter says, the consumer would absorb the increase in cost through elevated electric rates. Commenter says, as it stands, the electric rates for consumers in interior and rural Alaska are some of the highest in the country. 
Commenter 7893 states, Alaska's electric system is unique compared to the contiguous Lower 48 states and Alaska-specific considerations are necessary for these unique circumstances. Commenter says, Alaska electric utilities will be negatively impacted by an indiscriminate approach to environmental regulations based on erroneous assumptions that inexpensive natural gas is available and that there are robust electric grid systems like those in the contiguous 48 states. Commenter says, Alaska's diverse and isolated electric grid systems are not in the same category as interconnected contiguous US electric systems.
Commenter 7893 states, impacting the reliability of Alaska's electric utility sector puts the safety of all Alaskans at risk. Commenter says, the most important job of Alaska electric utilities is to provide reliable electric service to our communities through the extreme cold, lengthy and dark winter months. Commenter says, reliable electric service is a critical life and safety concern of every Alaskan. Commenter says, unlike interconnected utilities in the contiguous U.S., Alaska utilities do not have the option of relying on an integrated grid system for backup support. Commenter says, Alaska electric utilities have enough challenges with generating and distributing reliable power without the burden of the GHG NSPS where natural gas is not available. Commenter says, the cost of partial CCS will be exorbitant and cannot be supported by the state's small population that is spread over a vast land.
The EPA's modeling, conducted using the Integrated Planning Model (IPM), as well as modeling conducted by the U.S. Energy Information Administration (EIA) showed that new generating capacity built through the period of analysis would be in compliance with the standard even in the absence of the regulation. This finding held true even under a number of alternative scenarios. As a result, the EPA projected there would be negligible costs, benefits, or energy impacts associated with the rule in the period of analysis. Additionally, there are not expected to be impacts to reliability.
Affordability and reliability in Texas (ERCOT)
Commenters (1695, 3107, 5512, 9423, 9777, 10965) provide comments regarding the impact of the proposed rule on affordability and reliability in Texas.
Commenter 1695 states, as an economic developer from the Rio Grande Valley region that includes the first and third poorest MSAs in the country, according to the U.S. Census, he is concerned with the impact these new standards will have on electricity rates. Commenter says, our region cannot afford higher rates and quite frankly, for the outcomes stated above, neither can the State of Texas.
Commenter 3107 states, Texas, and especially north Texas, is a fast-growing and economically vibrant region. Commenter says, continued economic growth depends on a reliable supply of low-cost electrical power. Commenter says, recent reports by ERCOT and NERC express concerns about the Texas power grid maintaining power reserve margins adequate to avoid power shortages over the next several years. Commenter says, primary power adequacy concerns reflect high summer demands with heavy air conditioning loads. Commenter says, however, in January, Texas power consumers received a startling wake-up call when ERCOT came surprisingly close to implementing rolling power outages because of extreme cold temperatures and unexpectedly high demand. Commenter says, regulations that restrict development of new power plant construction, such as EPA's proposed greenhouse gas rules, could lead to further diminution of the Texas power grid's ability to meet consumer demand. Commenter says, this is a threat to Plano's businesses that depend on this power to be there when they need it.
Commenter 3107 states, with an economy growing almost 50% faster than the national average in 2012, and much of this growth in north Texas, including the city of Plano, it's critically important that EPA' s actions don't restrict continued critical access to low-cost dependable power. Commenter says, in light of potential decreased power availability and increased power costs, negatively impacting Plano Chamber members, as well as the surrounding communities we serve, we recommend that EPA either withdraw its proposed greenhouse gas regulation for new power plants, or set the emissions standard to a level that can be achieved by newly constructed power plants using existing demonstrated and commercially available technology. 
Commenter 5512 states, North Texas, and especially Frisco, is a fast-growing and economically vibrant region. Commenter says, continued economic growth depends on a reliable supply of low-cost electrical power. Commenter says, recent reports by ERCOT and NERC express concerns about the Texas power grid maintaining power reserve margins adequate to avoid power shortages in upcoming years - both during summer and winter months. Commenter says, regulations that restrict development of new power plant construction, such as the EPA's proposed greenhouse gas rules, could lead to further diminution of the Texas power grid's ability to meet consumer demand. Commenter says, this is a direct threat to Frisco's businesses that depend on this power to be there when they need it. Commenter adds, where demand increases beyond supply, simple economics dictates that power prices will increase. Commenter says, under the EPA's proposed new regulations, increased power costs could become the norm throughout many portions of the country, including Texas and Frisco specifically. Commenter urges the EPA to not allow reduced power capabilities and increased power costs to occur. Commenter says, the position of the Frisco Chamber of Commerce is shared by other business organizations, including the Texas Association of Business and the US Chamber of Commerce.
Commenter 9423 states, decreased fuel diversity in the electric power generation industry will have adverse consequences for affordable and reliable electric power in the nation. Commenter says, decreased affordability and reliability of the power system poses risks to public health, safety, and to the economy.
Commenter 9423 states, decreasing the fuel diversity in the electric power generation industry and relying too heavily on one particular fuel source will have adverse consequences on the national electrical power system, both in terms of reliability and affordability. Commenter says, recent gas delivery issues in northern states have shown that an over-reliance on one fuel type can lead to severe short-term price dislocations, and in some cases, curtailment of generation due to fuel deliverability issues. Commenter says, an unreliable or unaffordable power system would have serious effects on public health and safety, especially for vulnerable low-income populations. Commenter says, just a few examples of the effects of an unreliable power system include a lack of adequate lighting, heating, or cooling for homes, and lack of appropriate refrigeration, cooking, or sanitation facilities. Commenter says, all of these conditions could lead to injury or disease. Commenter says, essential service providers such as hospitals, police departments, water and sewer utilities, fire departments, and others also depend on having reliable electricity to fulfill their necessary duties that keep people alive and protect citizens against danger.
Commenter 9423 states, businesses in Texas and across the nation are critically dependent on the reliable delivery of reasonably-priced electricity to support their operations. Commenter says, an unreliable or excessively costly power system would have major adverse impacts on productivity and business revenue.
Commenter 9423 states, the ERCOT grid in Texas is unique in the United States in that it is wholly intra-state and essentially isolated from the two other U.S. grid interconnections. Commenter says, additionally, regulatory changes can have a different impact on market prices and reliability in the ERCOT region than in other regions of the country due to the energy-only nature of the ERCOT market.
Commenter 9423 states, the federal EPAct05 recognized the importance of ensuring reliability of electric grids by creating an Electric Reliability 0rganization ("ERO"). Commenter says, the ERO function is performed by the North American Electric Reliability Corporation (NERC), which oversees a vast set of reliability standards that govern operations and planning and are designed to ensure the reliability of the bulk power system. Commenter says, under the NERC reliability construct, ERCOT is designated as both the Reliability Coordinator and the Balancing Authority, and as a Transmission 0perator for the ERCOT Region. Commenter says, ERCOT is also registered for several other functions, including the key planning function of Planning Authority. Commenter says, the Texas Reliability Entity, Inc. monitors and enforces compliance with reliability standards for NERC, develops regional standards, and monitors and reports on compliance with the ERCOT Protocols.
Commenter 9423 states, the ERCOT grid is unique in the United States in that it is wholly intra-state and essentially isolated from the two other U.S. grid interconnections (the Western and the Eastern Interconnections). Commenter says, the ERCOT grid is not synchronously connected outside of the state, and there is limited ability for the ERCOT region to import or export electricity. Commenter says, there are 5 asynchronous ties between ERCOT and other interconnections: two linking ERCOT and the Eastern Interconnection (with a combined capacity of 820 MW), and three linking ERCOT and the electrical grid in Mexico (with a combined capacity of 286 MW). Commenter says, flows on these asynchronous ties are scheduled by market participants. Commenter says, ERCOT can request support from neighboring regions during grid emergency events. Commenter says, Aside from these limited asynchronous ties, from an electrical standpoint, the ERCOT region is an island that must independently ensure its own electric reliability.
Commenter 9423 states, generating capacity in the ERCOT region consists of a mix of generation technologies, fueled by coal (both lignite and sub-bituminous), natural gas, nuclear, wind, and other sources. Commenter says, almost forty percent of the energy generation in the ERCO0T region comes from coal.
Commenter 9423 states, ensuring reliability requires a constant balance between supply and demand. Commenter says, unlike gas or water, electricity cannot be efficiently stored in large quantities - it must be generated to meet demand on a real-time basis. Commenter says, this means generation and transmission operations must be monitored in real time, 24 hours a day, to ensure a reliable and continuous flow of electricity. It is critical that ERCOT has enough generating capacity to meet demand at every given moment.
Commenter 9423 states, ERCOT must have and maintain adequate installed capacity to cover the forecasted load on the system as well as to ensure reliability in case of events such as higher- than-projected demand (e.g., due to extreme temperatures) or unplanned generation outages (e.g., due to mechanical breakdowns), and limited generation from variable resources. Commenter says, reserve margins reflect a snapshot of existing and currently planned generation resources in excess of forecasted peak demand as a percent of that forecasted peak demand. Commenter says, having a sufficient reserve margin is necessary to ensure reliability in the case of these events that are outside of normal planning assumptions. Commenter says, in November 2010, the ERCOT board approved a minimum planning Reserve Margin target of 13.75 percent for the ERCOT region, based on the generally accepted industry criteria of limiting firm load shedding due to supply inadequacy to once every ten years.
Commenter 9423 states, ERCOT must also maintain a sufficient amount of generating capacity on-line in each hour to serve the load at that time, cover instantaneous variation in load and to instantaneously replace the generation from any generating units which suffer an unexpected maintenance disruption and are immediately disconnected from the electrical grid. Commenter says, this capacity is commonly referred to as operating reserves. Commenter says, when sufficient generation is not available to meet these requirements, ERCOT institutes a progressive series of emergency steps to address the problem. Commenter says, the initial stages focus on maximizing the use of supply resources and the later stages focus on the utilization of ancillary services provided by demand response. Commenter says, with respect to maximizing supply options, ERCOT notifies resource owners to make all generation capacity available and requests assistance from other grids. Commenter says, ERCOT's ability to import power from other regions is physically limited by the capacity of its direct current (DC) ties, which is approximately 1,106 MW. Commenter says, however, ERCOT is not entitled to any of that capacity. Commenter says, ERCOT has the right to request assistance, but there must be supply available in the adjoining region. Commenter says, in addition, there must be transmission capacity available to accommodate the import.
Commenter 9423 states, ERCOT has two demand-response programs that can be utilized in grid emergencies to reduce the amount of load connected to the grid in order to balance load with available generation. Commenter says, ERCOT typically procures as much as 1,400 MW of Load Resources and approximately 450 MW of Emergency Response Service (ERS); these programs are utilized by ERCOT in the second and third stages of a grid emergency to maintain system stability. Commenter says, when all of these operational tools are exhausted, ERCOT implements firm load shedding through the use of rotating outages. Commenter says, the progression of these stages is indicative of increased system stress related to increasing demand against decreasing operating reserve margins.
Commenter 9423 states, at any given time, available generating capacity is typically less than the theoretical maximum, for a variety of reasons. Commenter says, for example, all plants have planned and unplanned maintenance outages that can render them unavailable. Commenter says, available generating capacity in ERCOT changes daily and seasonally. Commenter says, it is lowest in the spring and fall when many plants are scheduled to be off-line for maintenance outages. Commenter says, on average, approximately 10,000 MW of generation capacity is unavailable during the spring and fall months due to scheduled periodic maintenance requirements. Commenter says, similarly, approximately 4,000 MW of generation capacity is typically unavailable at any given moment due to unplanned forced maintenance outages.
Commenter 9423 states, ERCOT typically experiences peak demand in the summer season (June-September). Commenter says, demand has been consistently increasing in Texas and is projected to steadily increase through 2023.
Commenter 9423 states, ERCOT administers the planning function for the ERCOT region. Commenter says, this function forecasts future peak demand and establishes transmission and supply requirements over the relevant period to maintain reliability of the electric grid. Commenter says, however, the ERCOT region, under state law, employs a competitive market construct for generation supply. Commenter says, in this environment, generation owners bear the risk of investment and decide when and where to build new generation, and whether to retire or idle existing generation, based on market conditions. Commenter says, ERCOT, the regulated transmission and distribution utilities (which provide only "wires" service and do not own or operate generation facilities), and the PUC do not have the authority to order generators to maintain or to add generating capacity. Commenter says, rather, the ERCOT market is designed to provide financial signals to competitive generation companies to ensure adequate generation capacity.
Commenter 9423 states, the ERCOT market is singular in that generating plants are paid only for the energy and the operational ancillary services they provide (commonly referred to as an energy-only market). Commenter says, as a result, regulatory changes can have a different impact on market prices and reliability in the ERCOT region than in other regions of the country.
Commenter 9423 states, this ERCOT energy-only market design has proven itself to be supportive of robust competition between generating technologies and fuel sources. Commenter says, a result of this market design is also that older, uncompetitive generating units tend to be retired more quickly, as units that do not operate are not able to earn any revenues. Commenter says, reserve margins in ERCOT have tended to be at or even slightly below the target reserve margin of 13.75 percent for the past few years.
Commenter 9423 states, in the ERCOT market, generation unit development decisions are made by independent investors, based on their analyses of market conditions and expectations of return on investment. Commenter says, as such, new investment in generating units will be made after the general market becomes aware of a system need. Commenter says, regulatory changes that result in significant changes in the market must have sufficient lead time so that the impacts can be assessed by the market and new investment can be made.
Commenter 9777 states, coal is a necessary fuel in the U.S. and ERCOT energy portfolio. Commenter says, given the recent history of extreme weather events in Texas, they remain concerned that power generation resources in Texas may be materially strained in an environment where regulation disincentivizes construction of new power generation, especially new coal-fueled generation. Commenter says, the demand for electricity in Texas has steadily increased in recent years. Commenter says, economic drivers in Texas have lead Texas energy demand (i.e., MWh produced) to grow 8% from 2005 to 2012. Energy demand is expected to continue to grow another 13% by 2020.
Commenter 9777 states, coal was a critical fuel during winter of 2013/2014. Commenter says, recent periods of extreme weather have threatened reliability and forced greater dependence on existing coal-fueled generation units. Commenter says, in Texas, the 2013/2014 winter saw extended cold weather across much of the State with ice and snow occurring as far south as Houston. Commenter says, meanwhile, in the Northeast, the demand for natural gas to heat homes has caused electricity prices to rise dramatically.
Commenter 9777 states, the EPA is wrong that natural gas can adequately replace coal-fueled units to satisfy the U.S. energy demands. Commenter says, the EPA's rule proposal, evidences EPA's belief that even if coal-fueled construction may not be practicable or economical because of the higher cost of CCS, basing the standard on an achievable emission rate is valid because "the basic demand for electricity could still be served by NGCC . . ." See 79 Fed. Reg. at 1481. Commenter says, this reliance on natural gas to replace new coal-fueled generation construction, combined with the real likelihood of existing coal-fueled generation retirement (driven by the Mercury Air Toxics Standards and other regulations) will leave the U.S. increasingly dependent on natural gas to power and to heat homes, resulting in an increased cost of living for millions of Americans. 
Commenter 9777 states, reducing the electricity supply during a time of steady demand growth through imposition of additional regulatory requirements on new coal-fueled generation, existing coal-fueled generation, and natural gas-fueled generation presents a real and significant risk to the reliability of the ERCOT grid, especially during spells of extreme weather. Commenter says, with the reliability issues already faced by the existing generation fleet, any regulation of existing units or modified units could place immediate and acute stress on the grid and exacerbate reliability concerns.
Commenter 9777 states, moreover, this regulation does not actually reduce existing GHG emissions; rather, it avoids GHG emissions attributable to new coal plants in the future. Commenter says, thus, this regulation is not expected to have any measureable effect on global temperatures. Commenter says, the EPA's final rule must balance the benefits of maintaining coal-fueled power as a part of a diverse fuel portfolio against the adverse consequences that may result from extreme weather as observed this past winter.
Commenter 10965 states, the EPA has failed to adequately consider the negative impacts the GHG NSPS would have on the availability of reliable and affordable electricity in many parts of the nation, including Texas. Commenter says, the EPA states that the GHG NSPS will have no adverse effect on the availability of reliable and affordable electricity based on its assertion that under the current energy market, no new coal-fired electric generating units will be constructed within the next eight years. Commenter disagrees. Commenter says, it is not clear that absent EPA's adoption of the GHG NSPS, no new coal-fired electric generating units will be constructed within the next eight years. In fact, Commenter believes that additional coal-fired electric generating units will be needed to ensure the continued availability of reliable and affordable electricity, at least in Texas. Commenter says, in light of that, and since the GHG NSPS will effectively prohibit the construction of new coal-fired electric generating units, the GHG NSPS would have an adverse effect on the availability of reliable and affordable electricity in Texas, as well as other parts of the nation.
As EPA has made clear in previous responses, EPA disagrees with these remarks because this rule will not limit diversity or threaten reliability.  EPA did not assume current energy market conditions would remain in the future.   Instead EPA carefully examined the potential for new coal through 2022 in IPM modeling, consulted independent projections from the Energy Information Administration, and analyzed historical trends in the use of coal (See the TSD in this Docket, "Trends in the Structure of Electric Power Sector Limiting Amount of New Coal".) Additionally, the RIA presents information from EPA's own modeling as well as EIA for 2020 and beyond that supports the conclusion that all new generating capacity constructed in the baseline will be in compliance with the standards, even in the absence of the rule. See RIA Chapter 4.
Affordability and reliability in Florida
Commenters (9320, 9661) provide comments on the impact of the proposed rule on affordability and reliability in Florida. 
Commenter 9320 states, the EPA has not adequately considered all the costs of CCS. Commenter says, because EPA's proposal effectively precludes coal-fired generation from ever being cost-effective, it is also decreasing fuel diversity as reliance on natural gas grows. Commenter says, as a result, Florida and its residents will increasingly be at the mercy of changes in fuel costs, which history demonstrates can be volatile. Commenter says, moreover, there will be impacts on jobs, especially as existing coal-fired generation is retired (an eventuality EPA is hastening with its Mercury and Air Toxics rule and other regulations) and replaced, with little to no potential for new coal-fired generation. Commenter says, this is because coal-fired generation is more employment intensive than natural gas-fired generation on a megawatt basis. 
Commenter 9320 states, the EPA's elimination of new coal-fired generation in Florida threatens electric reliability. Commenter says, the EPA's proposal effectively precludes new coal-fired generation in Florida, due to the obligation to include CCS. Commenter says, contrary to EPA's assertion, this is not appropriate, reasonable, or harmless in relation to Florida's unique circumstances, particularly as regards consequences for electric reliability in Florida. Commenter says, the EPA must analyze these circumstances and allow an opportunity for comment. Commenter says, the EPA concludes that its proposal would not prevent basic electrical demand from being met since natural gas-fired combined cycle plants could be built in areas where new coal-fired generation is effectively precluded. Commenter says, but, this overlooks the reliability issues posed by overreliance on natural gas-fired generation that is dependent on fuel supplied from sources subject to significant disruptions. Commenter says, Florida is uniquely situated in this regard and EPA must not preclude generation types necessary to meet the reliability needs of any given geographic area.
Commenter 9661 states, the proposed rule severely limits the prospects of coal-fired generation and will exacerbate an evolving imbalance in fuel diversity in Florida. Commenter says, therefore, the proposed rule will have adverse impacts on electrical reliability. Commenter says, they are concerned that the proposed implementation timeframe unnecessarily increases the reliability risk in the following ways: (1) over-reliance on natural gas in Florida; (2) reduced fuel diversity; (3) reduced operational flexibility due to proposed stringency in applying combined cycle standard to simple cycle operation for units capable of both cycles of operation. Commenter says, as the power industry in Florida contemplates what to modify, control and build in the future, and in ord.er to ensure a reliable, affordable supply of electricity in the future, the full suite of generating options will need to be relied upon. Commenter says, choosing to build natural gas-based plants now does not mean that utilities would not want to build new, efficient advanced coal-based units in the future for any number of reasons not included in EPA's analysis. Commenter says, the historical pattern of natural gas prices in the U.S. is one of volatility, not stability. Commenter says, this rule could result in significant economic impacts to residential and commercial customers, particularly minorities, elderly and economically disadvantaged customers.
EPA is not precluding the construction of new coal-fired generation, and the rule includes the flexibility to promote construction of new coal capacity with technology to meet the requirements.  For example, there are multiple compliance pathways to meet the final standard of performance, including compliance options that are not dependent upon use of CCS. Also, this rule only applies to new sources of base load and intermediate load electricity, and does not affect existing sources.  EPA's projections show that the nation's electric generating mix will continue to be diverse, with coal accounting for a substantial share of generation well into the future (this finding is corroborated by EIA and many other independent forecasting groups).  Finally, EPA explored scenarios using alternative assumptions with considerably higher future electric demand and higher natural gas prices, and no scenario resulted in new conventional coal by 2020.  Independent analysis and projections from EIA confirm this trend. EPA does not project any change in energy prices as a result of this rule, and as such does not expect negative impacts on the affordability or reliability of electricity. See RIA Chapter 4.
Affordability - rural, fixed income, low income, seniors, veterans
Commenters (2864, 4814, 4926, 4927, 8032, 9407, 9735, 10086) provide comments on the impact of the proposed rule on the affordability of electricity for rural consumers, and for fixed income, low income, seniors, and veterans.
Commenter 2864 states, many industry members, including those who have testified before us, project that utility customers could see dramatic increases in their rates as a result of these rules being enacted. Commenter says, utilities have stated that rates could increase 30 to 45 percent depending on the goals and timelines established. Commenter says, if a significant amount of additional coal-fired EGUs are shut down in this country, customers will pay not only the costs of shutting down these EGUs but also the costs of replacing them. Commenter says, asking customers to pay for plants that have remaining useful life is not a wise use of resources. Commenter says, furthermore, significantly increasing the costs of power will have a serious impact on the economy as the costs of goods and services will correspondingly need to increase. Commenter says, this will be particularly hard on the millions of jobless people and people living on fixed incomes in our country. Commenter says, the U.S. economy is still weak and many Americans are suffering. Commenter says, federal regulators need to be extremely methodical in approving new rules that could further weaken the economy.
Commenter 4814 states, increased electricity costs will likewise affect household incomes and measures should be in place to assist ratepayers who are least able to afford such increases in the cost of electricity to ensure that basic quality of life decisions do not become more complex.
Commenters (4926, 4927) state, the proposal puts at risk the ability to provide an abundant, reliable and affordable future electricity supply upon which our residents and industries can rely. Commenters say, a proposed rule of this nature effectively removes coal from consideration as a source of electricity for the growing energy demands of our state and nation because it sets unattainable standards. Commenters say, over 80% of Indiana's electricity is generated from units powered by coal. Commenters say, Indiana's low electrical rates, which are primarily fueled by coal, allow our state to rank as one of the highest manufacturing states in the nation. Commenters say, if finalized as proposed, this regulation will most certainly cause hardships in meeting increased energy needs and will have potential to decimate our industries, cause extensive job losses, and send our manufacturing overseas. 
Commenters (4926, 4927) state, the result of a rulemaking of this magnitude will raise and pass on future energy costs to consumers. Commenters say, energy prices have already increased as a result of recent EPA regulatory initiatives. Commenters say, even more increases in energy costs will affect all Hoosiers and be particularly detrimental to public facilities, as well as those citizens with fixed incomes or with low income. Commenters urge EPA to withdraw the proposed rule because it is fundamentally flawed and a defective approach to energy policy.
Commenter 8032 states, at current natural gas prices, a new natural gas combined cycle plant is less expensive on a life cycle cost of electricity basis than a new coal plant. Commenter says, the current break point for a new coal vs. new gas is approximately when natural gas cost rise above $6 per mmBTU. Commenter says, if CO2 capture is required for new coal plants, then the breakeven point will be when the natural gas cost exceeds $12 per mmBTU. Commenter says, this will create a significant increase in electricity prices and practically every consumer product price as a result. Commenter says, the cost for CO2 capture will significantly increase the cost of producing electricity. Commenter says, for cost of service provider with limited customers per mile electricity cost for our members will increase significantly and disproportionally high when compared to investor owned utilities with more customers per mile. Commenter says, the economy in rural America particularly cannot afford to suffer this type of impact nor can the economy as a whole. 
Commenter 9407 states, the facts about rural America's energy needs and usage exemplify why Commenter feels the EPA should keep their regulatory initiatives reasonable and their impacts on the rural electric consumer cost of electric service affordable. Commenter's concern is whether the rural electric consumers can reasonably afford their electric service under this proposal. Commenter says, even assuming EPA's unrealistically low cost assumptions under this proposal are valid, the rule would set national electricity energy policy for years to come by absolutely ensuring coal-based generation would be the most expensive new base-load generation option and likely too expensive as a realistic future generation option. Commenter says, consistent with Portland Cement v. EPA 665 F.3d 177 the EPA is required to take into account energy impacts and include a discussion of the proposal's impacts. Commenter thinks the countervailing factor of leaving the nation with one choice, natural gas, for most all new baseload generation weighs heavily against any proposal, like this one, that eliminates the coal option for nation's future energy mix. Commenter says, and yet the rulemaking docket lacks any disclosure that EPA considered this broader national policy implication of a one fuel baseload option.
Commenter 9735 states, ratepayers, or consumers, seemed to have played no real role in your consideration of this rule. Commenter says, if they had, we would have a seen greater attention paid to the outsize burden of this rule that would be placed on the backs of consumers across the country. Commenter says, experts on the issues of CCS that have actually looked at this, some within the same Administration, have stated that the pass through electricity costs to consumers of this proposed rule would be astronomical. Commenter says, Dr. Julio Friedmann, Deputy Assistant Secretary for Clean Coal at the Department of Energy, stated at a recent hearing before the House Energy and commerce committee that prices could rise as much as 80%. Commenter says, in some areas of the country where the current price per megawatt hour is lower than average, this cost increase could be even more significant. Commenter says, the EPA's failure to truly reflect this increased cost to consumers is a concern as I look at many residents in my state; middle-class, low-income, seniors, veterans, who can't afford such a rate hike, or would be forced to choose between electricity and other essential needs.
Commenter 10086 states, it is extremely troubling to see EPA's obvious failure to recognize the vital role of the electric utility industry in maintaining the health and well-being of the American people and to provide for balanced regulation. Commenter says, such a comparison might well be an example of how out-of-touch the agency is with regulation of the utility industry! Commenter says, electricity service is a life staple for residential consumers, in many rural areas a matter of life and death. Commenter says, certainly for many electric cooperative consumers, any increase in electricity costs must be compensated for by curtailing expenses somewhere else in the family budget. Commenter says, for this reason, we believe any potential increase in the cost of electric service should be closely linked to rational and realistic justification.
EPA is not precluding the construction of new coal-fired generation, and the rule includes the flexibility to promote construction of new coal capacity with technology to meet the requirements.  For example, there are multiple compliance pathways to meet the final standard of performance, including compliance options that are not dependent upon use of CCS. Also, this rule only applies to new sources of base load and intermediate load electricity, and does not affect existing sources.  It is not based on full CCS  -  the basis for the cost estimates in comment 9735, and necessarily is not associated with the electricity cost increases reflecting use of full CCS. EPA's projections show that the nation's electric generating mix will continue to be diverse, with coal accounting for a substantial share of generation well into the future (this finding is corroborated by EIA and many other independent forecasting groups).  Finally, EPA explored scenarios using alternative assumptions with considerably higher future electric demand and higher natural gas prices, and no scenario resulted in new conventional coal by 2020.  Independent analysis and projections from EIA confirm this trend. EPA does not project any change in energy prices as a result of this rule, and as such does not expect negative impacts on the affordability or reliability of electricity. See Chapter 4 of the RIA.
Affordability and reliability for farmers and ranchers
Commenters (3236, 8742, 8906, 9193) comment on the proposed rule's effect on affordability and reliability for farmers and ranchers.
Commenters (8742, 9193) state, farming is an energy-intensive business. Commenters say, farmers depend on reliable and affordable sources of energy to run their daily operations, including their tractors, grain-drying systems, and livestock barns among many other uses. Commenters support the availability and affordability of all sources of energy, including traditional (coal, gas, nuclear) and alternative (wind, solar, and other) sources. Commenter says, the availability of reliable electric service at a reasonable cost is critically important to our members and to Iowa's economy. Commenter says, the proposed standard for greenhouse gas emissions is therefore of great interest to farmers. Commenter says, one of the toughest challenges farmers face is dealing with the obstacles and variability Mother Nature often hands us. Commenter's grassroots membership supports policy opposing the regulation of greenhouse gas emissions. Commenter says, imposing added energy costs on our own economy while other countries are not held to the same standard puts U.S. producers and consumers at a disadvantage and serves little environmental purpose. Commenter says, in the end, merely reducing fossil fuel emissions without producing a measurable impact on world temperatures or climate cannot be regarded as a success. Commenter says, energy-related CO2 emissions from the United States have been falling since 2007, further raising our membership's concern over this proposed unilateral action.
Commenters (3236, 8742, 8906, 9193) state, the proposed standard does not provide the certainty that farmers and producers need in order to assure that they will continue to receive an affordable and reliable supply of energy. Commenters say, the EPA indicates there will be significant costs for utilities to comply with the new standards. Commenters say, the costs utilities will incur in order to comply with the new standards will be passed on to their customers - in many cases, farmers and ranchers. Commenters say, farmers and ranchers cannot set prices for their products (they are price takers and not price makers), so they lack the ability of many other sectors of recouping their costs by passing them on to customers. Commenters say, higher energy costs for farmers and ranchers mean higher farm input costs.
Commenter 3236 states, coal is an inexpensive, abundant and reliable source of energy in many parts of the country - the very type of electricity source that agriculture needs in order to remain viable and competitive in world markets. Commenter says, for farmers and ranchers in a large part of the country, coal supplies all or most of their electricity. Commenters (3236, 8906, 9193) say, as coal plants in these areas age and are de-commissioned, they are concerned that there will not be a reliable and affordable source of electricity to take their place.
EPA is not precluding the construction of new coal-fired generation, and the rule includes the flexibility to promote construction of new coal capacity with technology to meet the requirements.  For example, there are multiple compliance pathways to meet the final standard of performance, including compliance options that are not dependent upon use of CCS. Also, this rule only applies to new sources of base load and intermediate load electricity, and does not affect existing sources.  EPA's projections show that the nation's electric generating mix will continue to be diverse, with coal accounting for a substantial share of generation well into the future (this finding is corroborated by EIA and many other independent forecasting groups).  Finally, EPA explored scenarios using alternative assumptions with considerably higher future electric demand and higher natural gas prices, and no scenario resulted in new conventional coal by 2020.  Independent analysis and projections from EIA confirm this trend. EPA does not project any change in energy prices as a result of this rule, and as such does not expect negative impacts on the affordability or reliability of electricity. See Chapter 4 of the RIA.
NGCC and reliability
Commenters (7976, 9381, 10135) comment on NGCC units and grid reliability
Commenter 7976 states, modern, fast response combined cycle plants can typically provide about half to two-thirds of their rated plant output onto the utility grid within 10 minutes of the request of a hot start, thus qualifying that output as spinning reserve capacity. Commenter says, the NERC sub-regions require non-spinning reserves but the requirements are typically only 2% to 3% of the overall system load. Commenter says, even if a 500 MW combined cycle plant can only add 250 MW to the system non-spinning reserve capacity, the addition would be adequate to serve system load growth of over 8,000 MW. Commenter says, the startup curve [Figure 3 in the comment letter] was filed with the California Energy Commission and the South Coast Air Quality Management District in 2012 in support of a new plant permit for the AES Huntington Beach Energy Project. Commenter says, the application is for a 480 MW combined cycle plant in a 3x1 configuration. Commenter says, the curve is representative of how fast a modern combined cycle plant can start up.
Commenter 7976 states, utilities also need to support transmission grid reliability with system inertia, area voltage support, spinning reserves and/or load following capacity. Commenter says, these capabilities require the plant to be operating and synchronized to the grid while remaining available for long periods of time to provide power output ramping services. Commenter says, this means that it is generally more economical and more environmentally responsible to use efficient combined cycle (in lieu of simple cycle) generation resources to support transmission grid reliability with inertia, spinning reserve and load following capabilities.
Commenter 7976 states, precisely maintaining the balance between energy supply and demand is critical to grid reliability. Commenter says, recently, some electric utilities and transmission balancing authorities have expressed concern that high market penetration of renewables like wind turbine plants and solar energy plants will require firm back up resources to be capable of ramping rapidly to offset rapid, unexpected changes in the unpredictable output of the wind and solar resources. Commenter says, to maintain the grid's reliability, the grid's balancing authority needs to have flexible resources standing by; i.e., gas fired resources that can be reliably dispatched to ramp up or ramp down quickly in response to sudden changes in the wind or solar output. Commenter says, fortunately, modern combined cycle power blocks currently offered by GE, Siemens and others can ramp up and down for load balancing purposes rapidly like simple cycle GTs; typically at a rate of ~20% of rated plant capacity per minute. Commenter says, operating examples of such fast response combined cycle plants include the NCPA Lodi Energy Center and the NRG El Segundo Energy Center in California.
Commenter 7976 states, it is ironic that some sponsors propose to construct simple cycle capacity to backstop unreliable renewable resources rather than combined cycle capacity. Commenter says, the irony is that in forgoing the steam turbine capacity of a combined cycle plant, the sponsor is forgoing a "renewable" resource that is far superior to the wind or solar resources it supports. Commenter says, like wind and solar energy, the added steam turbine capacity does not require additional fossil fuel to produce electricity. Commenter says, and, compared to wind and solar, the steam turbine capacity has a much lower capital cost, is much more reliable and can be dispatched as needed. 
Commenter 9381 believes that any new source standard should be set in a way that recognized that market dynamics may shift in the future in ways not currently anticipated.  Commenter says, for example, with increased penetration of renewable energy sources, fossil fuel-fired electric generating facilities are likely to increase cycling (e.g. starting and stopping more frequently to respond to fluctuating demand).  Commenter says increased cycling of these units reduces their efficiency and increases their output-based CO2 emissions rate.  Commenter says natural gas combined-cycle (NGCC) units can provide limited ancillary and peaking services through duct firing and power augmentation to the turbine.  Commenter concludes, while they are not a substitute for simple-cycle turbines, this flexibility is important for grid function and reliability. 
Commenter 10135 states, the timing of these regulations could not be worse given the cumulative cost burdens to the development of new combustion turbine/gas turbine and combined cycle generation represented by additional requirements for permitting, emissions controls, compliance reporting and other associated requirements. Commenter says, the impact of these regulations is coming at a time when coal-fired generation is in decline, the future of nuclear generation is questionable, and renewable resources are not developing at a fast enough pace which presents a real and significant threat to future reliability.
In general, these comments support the principle that NGCC units are good sources for supporting the grid in terms of inertia, spinning reserve and load following.  EPA agrees with these comments.
Simple-cycle combustion turbines and reliability
Commenters (8952, 10052, 10239) comment on simple-cycle combustion turbines and reliability.
Commenter 8952 states, because simple cycle gas turbines cannot comply with emission limits that apply to units exceeding the one-third capacity and net output thresholds, they will be forced to adopt this arbitrary cap on their generation. Commenter says, nowhere in the record has EPA analyzed the effects of its changed proposed position on the existing fleet or future fleet of simple cycle gas turbines. Commenter says, nor has EPA considered the well-documented future demands anticipated in the energy markets and how barring reliance on simple cycle generation will affect energy markets, grid reliability and CO2 emissions under this rule.
Commenter 10052 states, based on their experience in operation of variable (renewable) and baseload (coal, nuclear, natural gas and geothermal) generation, they have frequently utilized their natural gas facilities to provide valuable peak and load-following generation. Commenter says, in order to ensure the continued deployment of renewable generation, they believe it is critical for the EPA to carefully examine the potential consequences of its proposed GHG NSPS for all new fossil-fueled electric utility generating units. Commenter says, the ability of simple-cycle combustion turbines to achieve a NSPS becomes an even more critical issue to ensure grid reliability as utilities ramp up integration of renewables to meet existing and future renewable portfolio standards and to reduce their carbon footprint. Commenter says, while EPA finds that historically simple-cycle combustion turbines do not supply more than one-third of their potential electrical output to the grid, this is not necessarily the case in the Western U.S., and may not be the case nationally in the future as renewables integration becomes increasingly necessary.
Commenter 10239 states, the risk of electricity disruption and price volatility will be increased by the EPA's proposed regulation of simple cycle turbines that are designed to provide peaking power. Commenter says, unlike baseload NGCC turbines, simple cycle turbines are designed to respond quickly to changing conditions and ensure a consistent, stable supply of electricity despite short-term fluctuations in supply and demand. Commenter says, while the EPA properly excluded simple cycle turbines in the 2012 proposal because of their different purpose and operations [77 Fed. Reg. at 22,398] the EPA has now reversed course and proposed to regulate them in the same manner as NGCC turbines if they supply more than one third of their potential electric output to the grid over a three-year period.
Commenter 10239 states, these changes will infuse more uncertainty into the electricity sector. Commenter says, regardless of their intended use, simple cycle turbines must respond to fluctuating weather, abnormal power usage, increased reliance on intermittent renewable energy, and unexpected outages from other generators, all of which is beyond their control. Commenter says, thus, while there is a risk that a simple cycle turbine could exceed the applicability threshold, neither the operator nor its customers would know until after the 3-year compliance period has ended. Commenter says, to mitigate that risk, operators may add emissions controls proactively, subjecting customers to potentially unnecessary costs. Commenter says, alternatively, they may seek to curtail production as they approach the applicability threshold, exacerbating grid instability. Commenter says, in either case, the increased uncertainty for simple cycle turbines will have ripple effects that harm retail consumers.
EPA disagrees.  Existing units can still meet reliability needs, and new NGCC units are more cost-effective to supply the base load generation needed meet the full range of reliability needs going forward than are simple cycle turbines.  
Effects of coal unit retirements on reliability and affordability
Commenters (1899, 4710, 7433, 7977, 8906, 8971, 9382, 9396, 9472, 9725, 10032, 2864) provide comments on the effects of coal unit retirements on reliability and affordability. 
Commenter 1899 states, in the competitive market, current market power prices do not support making these capital investments, such as uneconomic heat rate improvements, that will likely lead to further shutdowns of coal plants. Commenter says, in the regulated market, all costs will be passed on to the customer, which will increase electricity rates.
Commenter 4710 states, a moratorium on new coal-fired power plant construction will greatly impact grid reliability and increase the risk of rolling power outages and brownouts. Commenter says, NERC has also stated that 25 gigawatts of fossil-fueled generation (enough power to heat 20 million homes) has been retired since 2011. Commenter says, during this year's "Polar Vortex," 89 percent of the coal capacity that is slated for retirement by a major power provider in the upper Midwest was called upon to meet electricity demand. Commenter says, the EPA's proposed rule will exacerbate this trend and threaten the ability of utilities to supply power during peaks in demand.
Commenter 7433 holds that instead of coal units slowly and systematically giving way to more efficient generation, this rule aggravates an already stressed capacity market without allowing adequate new firm base load generation capacity to be built to offset the retiring plants. Commenter says, with ensuring overall system reliability as an agency goal, they are concerned that the rule has the potential to undermine two critical components that are vital to overall system reliability: diverse resource generation and price stability.
Commenter 7977, states their analysis shows, with moderate to high probability related to known and projected coal-fired EGU retirements, 81 GW of coal-fired electricity generating capacity nationwide will be retired.
Commenter 8906 states, the EPA proposes a standard of 1,100 lbs. of CO2 per megawatt hour that it admits cannot be met by proposed new coal plants, and the net effect of this "policy" seems essentially to eliminate the approval of any new coal-fired powered plants in the future. Commenter says, coal is an inexpensive, abundant and reliable source of energy and is heavily utilized in Nebraska. Commenter says, as coal plants in these areas age and are de-commissioned, they are concerned that there will not be a reliable and affordable source of electricity to take their place. Commenter says, at a time when our country needs to consider all types of energy, the proposed standard appears to eliminate one of the most widely used and inexpensive sources of energy. Commenter says, any standard for utilities should be realistic and achievable for all sources of energy.
Commenter 9382 states, in light of the issues that developed during the Polar Vortex cold snap last winter, Hoosier Energy is concerned with grid reliability due to the numerous plant closures as a result of EPA's other rules targeting the coal-fired utility industry, including the Mercury and Air Toxics Standards (MATS), which will only increase if EPA promulgates a CO2 existing source performance standard under Section 11l(d). Commenter says, as recently noted by FERC, "a number of mid-winter cold weather events stressed the electricity markets. High loads stretched resources and several new records for winter peak loads were set. New winter peaks were observed in MISO, PJM, NYISO, and SPP." Commenter says, Terry Boston, PJM's President and CEO, has also raised concerns surrounding reliability and fuel diversity. Boston was recently quoted as saying "I worry about fuel diversity," noting that coal and nuclear plants are retiring in PJM and that 74% of new generation is gas fired. Commenter says, this proposal will only serve to exacerbate problems with reliability and fuel diversity by increasing dependence on a fuel that proved inadequate just months ago throughout the United States.
Commenter 9396 states, more recently, events in the US have proven these articulated concerns about reliability to be warranted and demonstrated both the fragility of the electric grid and the reliance of the grid on fossil fuel plants that are set to retire as a result of environmental regulations. Commenter says economist Dr. Bernard Weinstein testified before the House Science Committee:
"The utility industry is already laboring to comply with these and a myriad of other EPA mandates. The result could well be a reduction in reserve margins, making less power available during periods of peak demand or plant outages. Imagine what would have happened in Texas and other southern states that rely heavily on coal-fired generation during the record summer heat wave of 2011 and this year's "Polar Vortex" if adequate reserve power had not been available. Not only would many energy-intensive industries have been forced to shut down, but rolling blackouts could have put the public's health at risk in the face of 100 degree-plus or sub-freezing temperatures week after week.
"This prospect was highlighted by the Electric Reliability Council of Texas, which operates the state grid, who stated that likely production cuts to comply with the proposed CSAPR rules alone would have threatened the state's ability to keep the lights on. American Electric Power Company has stated it will retire nearly 6,000 MW of generating capacity if the CSAPR rule is reinstated while Duke Energy will shutter 862 MW and Georgia Power another 871 MW.
"Should the EPA promulgate costly GHG emissions reductions for existing coal-fired plants, even more generating capacity is likely to go offline, further weakening the integrity of the power grids in Texas and elsewhere. And ERCOT has stated that it expects consumption in its power region to increase by 39.4 percent from 2007 through 2025, at the very time compliance with these and other regulations may force plant retirements." 
Commenter 9472 states that EPA regulations have contributed, so far, to the retirement or conversion of 380 existing coal units totaling over 51,000 megawatts of electric generating capacity in 33 states. Commenter says, these retirements pose increasing reliability challenges for the electricity grid and leave consumers exposed to higher energy prices. Commenter says, unfortunately, coal retirements could continue because of EPA's forthcoming CO2 regulations for existing power plants under section 111(d) of the CAA, as well as other pending EPA policies.
Commenter 9725 states, to maintain a diverse, reliable and affordable electricity grid, new higher efficiency coal units will be required to replace the retiring older coal, natural gas and nuclear electricity generation plants.
Commenter 10032 states, the proposed standard is unachievable. Commenter says, because of the state of current technology, new coal-fired plants cannot achieve the Proposed Standard of 1,100 lbs. of carbon dioxide per megawatt hour. Commenter says, new coal generation development will be impossible under the proposed standard. Commenter says, by EPA's admission, the proposed standard can only be met by natural gas combustion technology. Commenter says, this will eliminate future approval of any new coal-fired power plants. Commenter says, as coal-fired plants are decommissioned, it is our concern that no reliable and affordable replacement energy source will be available. Commenter says, coal is cheap, plentiful and reliable; the type of energy source agriculture and the rest of our country needs. Commenter says, the U.S. should consider all energy sources and set achievable and realistic goals.
Commenter 2864 states concerns in regards to the effects that shutting down a number of coal-fired EGUs will have on reliability. Commenter says, according to the most recent US Energy Information Administration 2014 outlook, 10.2 GW of coal-fired EGUs were retired in 2012 on top of the 23.4 GWs that have already been retired. Commenter says, it is expected that 39.3 GWs of additional generation will be retired between 2013 and 2023. Commenter says, there will also be 8.3 GWs of petroleum and 15.2 GW of natural gas generation retired during this time period as well which shows the rules have a much broader impact on the country's electric generation resources.  
 EPA is not precluding the construction of new coal-fired generation, and the rule includes the flexibility to promote construction of new coal capacity with technology to meet the requirements.  For example, there are multiple compliance pathways to meet the final standard of performance, including compliance options that are not dependent upon use of CCS.  Also, this rule only applies to new sources of base load and intermediate load electricity, and does not affect existing sources.  EPA's projections show that the nation's electric generating mix will continue to be diverse, with coal accounting for a substantial share of generation well into the future (this finding is corroborated by EIA and many other independent forecasting groups).  Finally, EPA explored scenarios using alternative assumptions with considerably higher future electric demand and higher natural gas prices, and no scenario resulted in new conventional coal by 2020.  Independent analysis and projections from EIA confirm this trend. EPA does not project any change in energy prices as a result of this rule, and as such does not expect negative impacts on the affordability or reliability of electricity. See RIA Chapter 4.
Debt on existing coal-fired EGUs
Commenter 9592 has provided electric power to the city of Gainesville and surrounding area for over 100 years. Commenter says, as a municipally owned utility, we are charged with providing reliable and economic electric power in an environmentally responsible manner. Commenter says, to meet both the emission reductions and compliance timelines for the Cross State Air Pollution Rule (CSAPR) rule and the Utility Mercury and Air Toxic Standards (UMATS) rule, GRU has spent more than $146,000,000 to add a dry circulating SO2 flue gas scrubber, selective catalytic reduction (SCR) and a fabric filter at the 235 MW Deerhaven Generating Station Unit #2 (DH#2). Commenter says, our investment in this generating unit is over $400 million in today's dollars with a significant debt still remaining. Commenter says, we are concerned that some of the policy precedents established in EPA's GHG NSPS for new units will result in higher electric rates due to over-dependence on one fuel source.
Commenter 9592 states, in the 1970s many Florida generating utilities, including GRU, were heavily dependent oil-fired generation.  Commenter says, the oil embargo of the 1970s resulted in a dramatic increase in our electric rates. Commenter says, in response to the oil embargo, Congress passed the Electric Power and Industrial Fuel Use Act of 1977, which disallowed the use of natural gas and oil for any new electric generating units. Commenter's original contract for DH #2 was for a primarily oil-fired steam electric generating unit. Commenter says, the Fuel Use Act required GRU to completely redesign DH #2 from an oil-fired unit to a coal-fired generating unit. Commenter invested millions of dollars on a new coal-fired generating unit not just because we sought a reliable domestic fuel source, but because we had no other choice for a new generation other than cost prohibitive nuclear generation to serve our consumers. Commenter concludes, it is important that EPA understands that GRU still carries considerable debt on DH #2 and forcing this unit into a premature retirement with an NSPS based on natural gas will be very costly to our ratepayers. 
This rule only applies to new sources of base load and intermediate load electricity, and does not affect existing sources.  Thus, the commenter's concern that the rule jeopardizes its investment is misplaced.  In addition, the BSER is not based on natural gas use (the commenter appears confused with the 2012 proposed rule, now withdrawn).  EPA's projections show that the nation's electric generating mix will continue to be diverse, with coal accounting for a substantial share of generation well into the future (this finding is corroborated by EIA and many other independent forecasting groups).  Finally, EPA explored scenarios using alternative assumptions with considerably higher future electric demand and higher natural gas prices, and no scenario resulted in new conventional coal by 2020.  Independent analysis and projections from EIA confirm this trend. EPA does not project any change in energy prices as a result of this rule, and as such does not expect negative impacts on the affordability or reliability of electricity. See RIA Chapter 4.
Proposed rule will not impair reliability
Commenters (0775, 9406) state that the proposed rule will not impair reliability.
Commenter 0775 states the rule will not have a significant impact on the availability of electricity, as there are only five planned coal-fired power plants according to DOE's EIA-860 data, totaling less than 2.5 megawatts of nameplate capacity. Commenter says, two of these planned power plants are not yet under construction, and one that is listed as in testing has apparently been damaged to the point where the project's credit rating was downgraded to B+. Commenter says, it is doubtful that even these five units will all be built or operated.
Commenter 9406 states that suggestions that the Proposed Rule might impair the reliability of the electricity supply system are a red herring. Commenter says, some point to the need to call upon existing coal-fired power plants during the recent polar vortex as providing an example of the need for energy diversity in the generation supply, with the unstated and illogical implication that, therefore, the proposal for a CO2 emissions rate limit for new fossil fuel-fired boilers based upon partial carbon capture and sequestration ("PCCS") will impair reliability. Commenter says, the Proposed Rule relates to new generation facilities only, and existing coal-fired facilities were clearly sufficient to meet electricity demand even during the polar vortex in New England, where the Regional Greenhouse Gas Initiative already regulates GHG emissions from both new and existing power plants. Commenter agrees with EPA's judgment that under current economic conditions, no new coal-fired power plants will be built in the near future. Commenter says alleged concerns about reliability are simply fanciful.
Commenter 9406 states the new source standards should be designed to give the correct signals to guide investment in new infrastructure related to electric power. Commenter says, that infrastructure lasts for 40 years or more. Commenter says, meeting the objective of the United Nations Framework Convention on Climate Change to prevent dangerous anthropogenic interference with the climate system will require an 80% reduction of worldwide emissions by 2100 and far greater reductions if the United States is allocated its per capita share. Commenter says, new infrastructure must be planned and designed in light of this fact.
Commenter 9406 states there is currently significant excess generating capacity in existing NGCC plants that can be used without impairing reliability.  Commenter says, the development of shale oil and "wet" shale gas formations to develop oil supplies has created an oversupply of natural gas that has driven the prices of natural gas below the price necessary to support development of new dry gas wells. Commenter says, undeveloped shale gas resources can provide more than sufficient supplies of natural gas to meet the nation's interim energy needs, without new generating capacity with emissions rates far higher than what will be necessary to meet national and global climate change goals. 
The EPA largely agrees with these comments, although the final standard of performance is not designed to meet an environmental goal or a priori level of reduction (per commenter 9406), but rather reflects a considered choice based on the statutory factors enumerated in section 111 (a).
Natural gas-fired generating units are essential to reliability
Commenter 9779 states, natural gas-fired generating units provide reasonably-priced, environmentally-friendly power that is essential to the reliable operation of the transmission grid and the integration of renewable resources. Commenter says, the outlook for low price gas has made natural gas turbine technology approximately forty percent cheaper to construct and operate than coal.
The EPA appreciates the information provided by the commenter which is consistent with the EPA's own analysis.
Measure promotion of energy diversity and independence
Commenter 10034 states, that the EPA's expected outcomes of the proposed rule include: (1) EPA asserts that this rulemaking reduces uncertainty, and will promote energy diversity. (79 FR 1496); and (2) EPA expects that the use of EOR from EGU captured carbon will lower production costs for domestic oil, which will promote energy independence. (79 FR 1480). Commenter says, the EPA should measure whether its rule does in fact help to promote the goals of energy diversity and energy independence.
These statements are presented in the preamble and strongly supported by analysis in the RIA, including analysis over a range of potential futures.
3.7.1 Proposed Rule Precludes Coal-Fired Generation
The proposed rule is part of an anti-coal agenda
Commenters (3236, 3593, 5631, 8742, 8971, 9194, 9396, 9650, 10046, 10951) characterize the proposed rule as an anti-coal agenda.
Commenters (3236, 8742) state, the proposed rule demonstrates that the administration seeks to end new coal-fired electrical generation through regulation. Commenters say, the EPA admits as much in the proposed standard by stating that the only fossil fuel plants that can meet the standard are natural gas plants. Commenter 8742 says, the presence of CO2 is not just in the U.S. but worldwide. Commenter 8742 says, imposing added energy costs on our own economy while other nations are not held to the same standard puts the U.S. at a competitive disadvantage. Commenter 8742 says, in the end, merely reducing fossil fuel emissions without producing a measurable impact on world temperatures or climate cannot be regarded as a success. Commenter 3236 says, the net effect of this "policy" seems essentially to eliminate the approval of any new coal-fired powered plants in the future. Commenter 3236 adds, while existing and modified EGUs are not included in this NSPS, this proposal is widely perceived as a pre-cursor to the standards that will ultimately be applied in the regulation of existing units. Commenter 3236 says, at a time when our country needs to consider all types of energy, the Proposed Standard appears to eliminate one of the most widely used and inexpensive sources of energy. Commenter 3236 says, any standard for utilities should be realistic and achievable for all sources of energy.  
Commenter 3593 states, the EPA's stance on regulating power plant GHG emissions, as stated by EPA Administrator Gina McCarthy, is that under the new round of rulemaking including the current NSPS rule, coal will still be viable, a stance one would expect her to assert given that this must be the case under the law. Commenter says, likewise, Janet McCabe, then a senior aide in (and now the proposed nominee to lead) the Office of Air and Radiation, said in a hearing before the House Energy and Commerce Committee that, "We are not saying you can't build a new coal plant in America," and that there will be a "clear regulatory path" for new coal plants to be constructed. Commenter says, like efforts to rewrite the vow to "bankrupt" coal-fired power plants, this runs contrary to the proposed rule and is directly contrary to express assertions of the president and vice-president when campaigning for office (Joe Biden also stated, "No coal plants here in America," he said. "Build them, if they're going to build them, over there. Make them clean."
Commenter 3593 states, many in the industry as well as the instant rule's critics argue, however, that these regulations don't seek to make coal cleaner, but to "bankrupt" the industry altogether as then candidate Obama vowed. Commenter says, House Energy and Commerce Committee Chairman Fred Upton (RMI) characterizes the record as indicating that, "The EPA is holding the coal industry to requiring fuel-switching, impossibly characterizing a gas turbine as the best available emission reduction technology for a coal plant - impossible standards." Commenter says, indeed, this rule as originally proposed was pulled due to it obviously. 
Commenter 3593 states, the Sierra Club's "Beyond Coal" campaign has a stated objective that is perfectly aligned with that result as well as with then-candidate Obama's vow, put into practice immediately by his EPA political appointees and manifesting itself in the instant proposed rule. Commenter says, featured prominently on their website, the Sierra Club states that it is its goal "to prevent new coal plants from being built," to 'Retire one-third of the nation's more than 500 coal plants by 2020,' and to 'Keep coal in the ground." Commenter says, it is the principal objective of the environmentalist pressure group industry, and by chance we have obtained records documenting the Agency's improperly close collaboration with Sierra Club, as that industry's lead point of contact and advocate, on this shared agenda. Commenter says, however, this agenda is explicitly contrary to the stated public goals of the EPA as it pursues the instant rulemaking.
Commenter 3593 states, it is noteworthy that every member of the EPA's senior leadership who has not made his or her career in the EPA or state level environmental agencies has a history of employment with environmental pressure groups, including most of the groups that expressly urged the executive branch to use all means potentially at its disposal to eliminate coal, and ultimately all hydrocarbon or "fossil" fuels. Commenter says, the emails cited herein and obtained via FOIA requests show clearly that people who spend years or decades trying to do something as activists, then migrate into government, do not arrive at the issues anew, but come in to perform the same objective but as government. Commenter says, indeed -- as most obviously manifested in EPA bringing in Massachusetts v. EPA advocate Lisa Heinzerling nominally to explore whether or not the Agency should do what she had committed years of her professional life demanding it do -- these activists are brought in precisely because of these predispositions and histories. Commenter says, the courts have recognized that, at some level, this is to be expected, but that when "a clear and convincing showing that he has an unalterably closed mind on matters critical to the disposition of the rulemaking," is shown, they should be disqualified.
Commenter 3593 states, the EPA paid the equivalent of lip-service to the obvious, formal (associational) conflicts of interest with these same groups -- such that, e.g., a former Sierra Club activist would liaise with Natural Resources Defense Council, and vice versa, yet still with former allies and colleagues with whom they worked together on the issues such as Sierra's John Coequyt working with former NRDC official Michael Goo to stop "Zombie" coal plants from being resurrected, or serially corresponding with Coequyt on plants the greens' and EPA's campaign are forcing off-line. Commenter says, agency correspondence reveals EPA officials with a predetermined bias colluding on this rule making (and the efforts that EPA says compelled this rule making) with outside groups that have the same predetermined bias, achieving a predetermined outcome. Commenter says, problematically for this proposed rulemaking, this outcome is the stated objective of the environmental pressure groups, and contrary to the stated (legally required) position of the EPA.
Commenter 3593 states, what's more, the closed mind of these officials creates a situation where they "entirely failed to consider an important aspect of the problem." Commenter says, ostensibly, all of these regulations are in pursuit of mitigating climate change by limiting man's contribution of CO2 emissions to the global CO2 budget, which we are told by some defenders is the most "urgent" problem that we face. Commenter says, however, under no scenario will this actually lead to lower global levels of CO2 let alone a detectable climatic impact, which is also the consensus view of even the "global treaty" Kyoto, perfectly implemented for 100 years. Commenter says, even as EPA and its third-party allies proceeded with this rulemaking despite knowing it would have no impact on the asserted problem being addressed -- climate change -- they completely ignored the economic problems caused by this regulation which by law must be considered. Commenter says, the rule represented a shared vision, a political and/or ideological one (to end the use of coal in America) but most certainly was not a rule making intended to mitigate climate change. Commenter says, this altered and improper purpose likely explains the Agency's decision to not consider the balance of interests, Commenter says, rather, the Agency managers who had come to EPA had already decided this proposed rule was something that they were going to put in place, before they ever entered federal service. Commenter says, incorporating by reference our discussion here and in Comment of the president's stated objective of propping up an economically failed but political selected industry. Commenter says, that these failings of the rulemaking were not considered is further evidence of predetermination, of course; it had been decided, here is our answer, now get us there.
Commenter 3593 states, the president on whose behalf this rule is promulgated has plainly stated the objectives of this rule and related rules that EPA insists it is compelled to issue as a result of the endangerment finding, which are to "bankrupt' coal-fired power plants and "finally make [renewables] profitable". Commenter says, he has either consistently misstated the objectives or he consistently told the truth about them. Commenter says, we believe it is the latter, and his effort to use the instant rule to "bankrupt' coal is in fact problematic for the instant rulemaking, for reasons asserted elsewhere in this Comment.
Commenter 3593 states, regardless, that this objective not grounded in the urgency of a climate crisis was known to EPA officials, who nonetheless proceeded in spite of relevant evidence that these regulations would not accomplish their stated goal and would have serious economic consequences, because the real goal was to bring about the economic viability of politically favored industries and the end of politically disfavored industries. Commenter says, it amounts to nothing but a massive transfer of wealth from one industry to another. Commenter says, this, along with other factors, such as their conflicts of interests, lead to a predetermined, arbitrary outcome that was not based on the facts on record or the law, but personal bias and for reasons not on the record or that Congress could not have considered in passing the CAA.
Commenter 5631 states, the proposed limits on CO2 emissions seem to be aimed at pricing coal out of the next generation of electricity production, eliminating one of our country's major competitive advantages - energy. Commenter says, the results of the proposal will ultimately be higher electricity costs and lower energy reliability. Commenter says, a U.S. economy that has always thrived on abundant, affordable energy could soon be an economy facing energy scarcity if we outlaw our most abundant resources. Commenter says, policy actions that increase the cost of energy will have a direct negative impact on the U.S. economy at a time when jobs and household incomes are the overriding quality of life issues in America. 
Commenter 8971 states, the CO2 NSPS will have a significant negative impact on America's domestic energy market going forward and the trickle-down effects of this rulemaking will hit every American consumer, producer, business, State, and municipality. Commenter says, in Ohio, the negative impacts of the CO2 NSPS will be fundamental and profound, both directly and indirectly. Commenter says, carrying an "end justifies any means" policy perspective, the EPA has ignored science, economics and common sense when developing the CO2 NSPS. Commenter says, further, the EPA seeks to expressly destroy the coal industry and destabilize this country's energy industry by directly forcing the power markets to hastily move from coal to gas. Commenter says, this bias against coal will have long-lasting effects on this nation which will far outlive the current policy whims in Washington. Commenter says, from a human perspective, the EPA seeks to fundamentally alter the lives of families in our Appalachian mining regions by taking away any ability to earn a living as a hard-working, highly-skilled coal miner.
Commenters (9194, 9396) state, the EPA's aggressive coal-related regulatory agenda is adding unprecedented systemic risk and threatens electricity supplies and potential blackouts. Commenter 9396 says, the EPA has declined to conduct cumulative analyses of its multiple rulemakings and their potential impact on electric reliability. Commenter says, private sector analyses consistently attribute much higher costs and far greater coal-fired power plant retirements than EPA. Commenter says, the EPA's application of national averages in estimating the impacts of this rule serve to disguise far greater vulnerability of certain regions in the country to potential electric shortages and price spikes.
Commenter 9396 states, the American Coalition for Clean Coal Electricity (ACCCE) in January 2014 updated a list of coal retirements or conversion announcements for the time period of 2010-2022 using a SNL Financial Database and company announcements. Commenter says, while there are multiple reasons that coal plants might be shuttered, this list only included those retirements and conversions directly attributed to EPA regulations by the source. Commenter says, those attributed to EPA regulations totaled 330 units (51,000 MW) in 33 states; approximately 16 percent of the U.S. coal fleet. Commenter says, this stands in sharp contrast to EPA' projected 9,500 MW coal retirements due to its CSAPR and MATS rule.
Commenter 9396 states, various regions of the country are going to experience a far greater impact from these rules than the national average. Commenter says, several regional entities and Regional Transmission Organizations indicate EPA regulations are going to cause severe electric reliability problems. Commenter says, both the Electric Reliability Corporation of Texas and the Southwest Power Pool (SPP), that are responsible for grid operations in eight states in the southwest, have stated that the CSAPR rule threatens reliable operations. Commenter says, according to SPP in a September 9, 2011 letter to EPA on CSAPR, SPP expects "negative implications to the reliable operation of the electric grid in the SPP region raising the possibility of rolling blackouts or cascading outages that would likely have significant impacts on human health, public safety and commercial activity." 
Commenters (9194, 9396) state, the EPA should develop a proposal which specifically considers important national goals, including fuel diversity, electricity affordability and reliability, economic growth, jobs and national energy security.
Commenter 9650 states, the EPA's action mandating implementation of CCS technology for new coal-burning EGUs, is the latest in a string of regulations promulgated under the CAA that will undermine private industry by imposing erroneous and unjustified burdens on the national economy. Commenter says, the Agency proposes a rule serving no other purpose than to establish an erroneous foundation for imposing massive restrictions on sources providing nearly one quarter of this country's energy.
Commenter 10046 states, since the experts agree that the only predictable result of the EPA proposal is the end of development of new clean-coal technology and the furtherance of an imprudent "dash to gas," the proposal lacks any legitimate environmental objective. Commenter says, it is therefore not unreasonable to conclude that the proposal is an ultra vires attempt to use the "obligation" to regulate GHG emissions under the CAA to achieve a pre-determined political objective of dramatically reducing the use of coal in the United States, even if that means sacrificing the Obama Administration's stated climate change objectives and the CCS-development policies that would be logically necessary to pursue those objectives. Commenter says, using the federal government's regulatory machinery to further an unlawful "no-new-coal" agenda is not a permissible use of the CAA.
Commenter 10046 states, finding no plausible climate change policy basis for EPA's proposal, one is left to conclude that it is motivated by a desire to ban construction of new coal units for the foreseeable future, which will undoubtedly be the unfortunate result if this proposal is finalized. The proposal cynically uses a climate change imperative to set a GHG performance standard that vendors cannot guarantee, and establishes a risk that developers cannot assume. But EPA cannot even claim any GHG reductions for its efforts because, as it acknowledges, "EPA does not project any new coal-fired EGUs without CCS to be built in the absence of this proposal." It also specifically contradicts the Administration's claimed "all of the above" energy strategy, or at least revises that strategy to one of "all of the above, except coal." This is clearly at odds with the President's promise set forth in the February 3, 2010 Presidential Memorandum establishing the CCS Task Force.
Commenter 10046 states, for decades, the coal industry has supported high-paying jobs for American workers, and coal has provided an important domestic source of reliable, affordable energy. At the same time, coal-fired power plants are the largest contributor to U.S. [GHG] emissions and coal accounts for 40 percent of global emissions. Charting a path toward clean coal is essential to achieving my Administration's goals of providing clean energy, supporting American jobs, and reducing emissions of carbon pollution. Rapid commercial development and deployment of clean coal technologies, particularly [CCS], will help position the United States as a leader in the global clean energy race. 
Commenter 10046 states,  the EPA's proposal contradicts the President's own clean coal policy promises by mandating CCS before it is ready, and, in so doing, defeats the Administration's own stated policies and goals on climate change, objectives which cannot be met without CCS for both coal and gas generation. A new coal-fired plant developer will have to bet billions of dollars on commercially unproven CCS technology to comply with the new GHG emissions standard. It defies common sense to establish an NSPS that pays mere lip-service to the technical viability of the immature CCS technologies without accounting for the effects that added compliance risk will have on developers and financers of new CCS projects. The Global CCS Institute specifically cautions that government policies not "disadvantage" CCS, and that because "first mover projects incur higher risks and upfront costs than later projects[,] appropriate recognition of this should be taken into consideration in the framing of financial and policy support for first movers." 
Commenter 10951 states, the experience of this past winter reveals just how dangerous EPA's anti-coal policy is. Commenter says, at the same time as EPA has forced tens of gigawatts of existing coal plants to retire, the Northeast, Mid-Atlantic, and Midwest experienced record-setting electricity and natural gas prices. Commenter says, spot prices for natural gas in the Mid-Atlantic on January 22 surged almost 340 percent to $45 per million British thermal units, and natural gas prices in New York City rose more than 780 percent. Commenter says, the Federal Energy Regulatory Commission was forced to waive its $1,000/MWh cap on wholesale electric prices as Midwest and Mid-Atlantic Prices shot up by $857/MWh. Commenter says, American Electric Power, one of the nation's biggest utilities, said that 89 percent of its coal generation scheduled for shutdown beginning in May 2015 was running to keep the lights on during the early January cold snap. Commenter says, consumers were hit with hundreds and even thousands of dollars of unexpected electricity and natural gas bills. 
Commenter 10951 states, as Philip Moeller, a member of the Federal Energy Regulatory Commission, recently stated, "[w]e are now in an era of rising electricity prices" because of the steady reduction in generating capacity. "If you take enough supply out of the system, he said, "the price is going to increase." Commenter says, warning that the nation's electric grid is unprepared for the expected coal plant retirements, Moeller testified to Congress that "the experience of the past winter indicates that the power grid is already at the limit". Commenter says, we can hope for mild winters and summers over the next several years, but hoping for mild weather is not a practical method of planning to meet economic growth and public safety." 
Commenter 10951 states, the EPA's anti-coal policies are profoundly misplaced and will undermine the dramatic societal benefits that low-cost electricity from coal has created. Commenter says, it is not necessary to speculate on the effects EPA's anti-coal policies will have. Commenter says, they have been tested in other countries and the verdict is in: large-scale electric rate increases are the result. Commenter says, every country that has aggressively sought to promote renewable and discourage coal usage has experienced large electricity increases. Commenter says, comparing U.S. electricity prices to European Union electricity prices tells the story.
Commenter 10951 states, between 2009 and 2013, the average energy bill for EU consumers increased by some 17 percent, while energy costs for industrial users jumped by 21 percent. Commenter says, between 2005 and late 2013, the average price of residential electricity in the EU rose by 55 percent, and industrial electric rates jumped by 26 percent. Commenter says, the average U.S. household now pays 12 cents per kilowatt-hour; about a third of what the same amount of electricity costs in Germany. Commenter says, European steelmakers now pay twice as much for their electricity as do U.S. manufacturers. 
The rhetoric in these comments is significantly misplaced.  The final standard of performance is structured to assure that new coal capacity can be both lower CO2 emitting and be cost competitive with other non-NGCC baseload dispatchable capacity.  The EPA withdrew its initial proposal to base the standard on performance of NGCC; adopted a less stringent standard of performance in this proceeding than proposed; rejected full CCS as BSER; and exempted sources under development from the standard, even though such sources are "new" under the Act.  These actions are at odds with the commenters' narrative.  The EPA notes that responsible members of the generating industry itself have indicated that CCS can be a key to a viable future of coal-fired capacity.  See e.g., statement of Alstom senior Vice President for Power and Environment Policies Joan Macnaughton's statement (August 4, 2011): "AEP's decision to put Mountaineer II on-hold (sic) is a bellwether to our leaders on the consequences of uncertain climate policy.  The Validation Plant at Mountaineer demonstrated the ability to capture up to 90% of the carbon dioxide from a stream of the plant's emissions.  The technology works.  But without clear policies in place outlining options for cost recovery, power generators are hard-pressed to invest in its continued refinement."  The press release further states that Vice President Macnaughton "presented findings from a recently-conducted cost analysis showing that the cost of electricity generated by coal and natural gas plants equipped with CCS is competitive with other low or no-carbon energy carbon energy sources, such as wind, solar, geothermal, hydro and nuclear."  

The Proposed Rule relates to new generation facilities only, and existing coal-fired facilities were clearly sufficient to meet electricity demand even during the polar vortex in New England, where the Regional Greenhouse Gas Initiative already regulates GHG emissions from both new and existing power plants.
It is the proposed rule that will preclude new coal-fired generation
Commenters (9193, 9196, 9600, 9666, 9723) provide comments arguing that it is the proposed rule that will preclude new coal-fired generation.
Commenter 9193 states, at a time when the U.S. needs to consider all types of energy, the proposed standard appears to eliminate one of the most widely used and inexpensive sources of energy.  
Commenter 9196 is concerned that EPA is seeking to use the NSPS program to impose an effective ban on new coal-fired power plants in the US. Commenter says, claims that new coal plants are not precluded by the proposed rule are not consistent with the design or operation of the rule. Commenter says, as David Wright, President of the National Association of Regulatory Utility Commissioners, has explained: 
"Even the best performing coal units cannot meet the NSPS without CCS. The Proposed NSPS for GHG goes on to state that, "we are not proposing that CCS, including the 30-year averaging compliance option, does or does not qualify as the [best system of emission reduction] adequately demonstrated" but solicits comments on that decision. A commitment to resource diversity would encourage a separate NSPS [best system of emission reduction] for coal-fired plants and natural gas combined cycle units, keeping the categories separate as they have been historically."
Commenters (9600, 9666) state, that the EPA is wrong that, without a CCS-based NSPS, no coal-fired generation will be constructed; it is the promulgation of the proposed CCS-based NSPS that would preclude such generation.
Commenter 9600 disagrees with EPA's conclusion that the proposal if finalized will have no cost. Commenter says, the EPA reasons that few or no coal-fired units will be built in the future; therefore there will be little or no cost. Commenter says, however, the EPA has put "the cart before the horse". Commenter says, without this proposal, coal-fired EGUs could be built; with this proposal, a coal-fired EGU could not be built due to the extreme costs for CO2 capture. Commenter says, the EPA theorizes that future baseload generation will be natural-gas fired. 
Commenter 9666 says, the EPA asserts that "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." 79 Fed. Reg. at 1477. Commenter says, the EPA further states that it "does not project any new coal-fired EGUs without CCS to be built in the absence of this proposal." Id. at 1498. Commenter says the basis for this projection is EPA's assumption that, for the period from 2020 to 2040, supercritical PC plants cannot economically compete with NGCC combustion turbines. 
Commenter 9666 states, that the EPA states that it "does not project any new coal-fired [electric generating units ("EGUs")] without [carbon capture and storage (or sequestration) ("CCS") ]" will be constructed "in the absence of this proposal." Commenter says, the EPA bases this prediction on its assertion that, for the period 2020 through 2040, supercritical pulverized coal ("PC") units cannot compete economically with natural gas-fired combined cycle ("NGCC") combustion turbines. 
Commenter 9666 states, that the EPA's prediction is specious. Commenter says, an analysis undertaken by their consultant shows that the cost of supercritical PC plants becomes competitive with NGCC plants with only modest changes to the inputs that underpin EPA's prediction (i.e., overnight capital cost, finance charges, fixed and variable operating and maintenance charges, and fuel prices). 
Commenter 9666 says, the EPA relies on two inputs that are highly uncertain: (i) the "overnight" cost of capital for supercritical PC plants and NGCC plants; and (ii) fuel cost. Commenter says, to test the reliability of EPA's prediction, their consultant conducted sensitivity analyses to examine the effect of modest changes in overnight capital cost, finance charges, fixed and variable operating and maintenance charges, and fuel prices. Commenter says, these analyses show that the cost of supercritical PC plants becomes competitive with NGCC plants with only modest changes in these four inputs.
Commenter 9666 states, in sum, if this rule is finalized, new coal-fired generation will not be built, notwithstanding the national interest in utilities maintaining a diverse generation fleet to hedge against fuel price fluctuations and to maintain reliability. Commenter says, for decades, coal-fired generation has mitigated against natural gas price increases and gas-fired generation has hedged against coal price increases. Commenter says utilities must protect ratepayers from wide swings in fuel prices by maintaining a diverse portfolio of generation assets. Commenter says for most of their members, a balanced generation portfolio is not merely an objective; it is an obligation that comes with a duty to serve their customers. Commenter says, for these reasons, their members will construct new coal-fired power plants as part of their future generation mix if that generation is an economic alternative to natural gas. Commenter states, this proposal, if finalized, will prevent their members from doing so by making new coal-fired plants uneconomical as compared to natural gas-fired plants.
Commenter 9666 states, in its analysis, EPA fails to acknowledge the costs to the electric generating sector (and to the economy generally) of the fact that this proposed rule, and its April 2012 predecessor, have had a considerable chilling effect on companies and organizations that were planning before April 2012 to construct new EGUs and on those that would have planned to build such units absent this proposed rule.  Commenter says, this proposed rule - even prior to being finalized - represents a game-changer for the industry because, with CCS being undemonstrated, extremely expensive, and completely unfeasible in many parts of the country, the proposed standard for Subpart Da units effectively eliminates the use of coal as a viable option for the electric sector for the foreseeable future.  Commenter states, the proposed rule also will encourage owners and operators of existing coal-fired EGUs to continue to operate these units rather than retire them, out of concern that no new coal-fired units could be constructed for the foreseeable future if the proposed rule is promulgated. 
Commenter 9723 states, coal continues to be an economic electric generation resource option in the regions where Montana-Dakota operates, despite low natural gas prices. Commenter says, however, the EPA's re-proposal essentially eliminates coal as a new resource option for the company in the future. 
See previous responses, including response 3.3-16a (response to Cichanowicz).  The EPA reiterates that the new source performance standard does not ban new coal capacity, and, as part of the agency's responsibility to consider costs, is structured to preserve coal as price competitive with other non-NGCC baseload dispatchable technologies.         

("There is, indeed, a war on coal going on. But while politicians and industry lobbyists tend to identify the Environmental Protection Agency and the Obama administration as coal's chief antagonists, the array of forces facing the powerful black fuel is far greater..... The main foe coal faces is cheap natural gas. Along with renewables (which are getting cheaper and offer the prospect of emissions-free power), natural gas has captured significant territory that once belonged to the legions of coal").
The proposal portends a risky national energy policy
Commenters (9001, 9407, 9428, 9595, 9601, 9767, 10086, 10097, 10238, 10358, 10387, 10501, 10518, 10952) state that the proposed rule promotes a risky national energy policy.
Commenters (9428, 9595, 9601, 9767, 10086, 10358, 10387, 10518) state, the EPA has one standard of performance for fossil fuel-fired electric steam generating units and IGCC units and another for natural gas-fired stationary combustion turbines. Commenters say, left unchanged, these standards will drive the power industry to a natural gas only energy strategy. Commenters say, a national energy policy based on one fuel is foolhardy, and unnecessary under the CAA. Commenters (9001, 9428, 9595, 9601, 9767, 10238, 10501, 10358, 10387) say, the current proposal virtually ensures that new coal-based generation will be prohibitively expensive and will not be built.
Commenter 10952 states, when determining appropriate costs to be borne in connection with this rulemaking, any analogy between cost of cement manufacturing and cost of electric utility service is a poor one. Commenter says electricity service is vital for business and is a life staple for residential consumers, but in many rural areas it is a matter of life and death. Commenter says certainly for many electric cooperative consumers any increase in electricity costs must be compensated by curtailing expenses somewhere else in the family budget. For this reason Commenter believes any potential increase in the cost of electric service should be closely linked to rational justification. Commenter says, also, countervailing factors including non-air quality health impacts are among the factors EPA is to consider in determining BSER. See Portland Cement Ass'n v. EPA, 665 F.3d 177, 191 (D.C. Cir. 1973). Commenter's concern is whether the rural electric consumers can reasonably afford their electric service under this proposal. Commenter says even assuming EPA's unrealistically low cost assumptions under this proposal are valid, the rule would set national electricity energy policy for years to come by absolutely ensuring coal-based generation would be the most expensive new base-load generation option and likely too expensive as a realistic future generation option. Commenter says consistent with Portland Cement v. EPA 665 F.3d 177 EPA is required to take into account energy impacts and include a discussion of the proposal's impacts. Commenter thinks the countervailing factor of leaving the nation with one choice, natural gas, for virtually all new baseload generation weighs heavily against any proposal, like this one, that eliminates the coal option for nation's future energy mix. Commenter says, and yet the rulemaking docket lacks any disclosure that EPA even considered this broader national policy implication of forcing a one fuel baseload option.
Commenter 10952 states, it is noteworthy that concerns over natural gas availability prompted the U.S. Congress to enact the 1978 Power Plant and Industrial Fuel Use Act that required all new electric generating facilities to be "coal capable." Commenter says due to the capital cost differentials between facilities constructed to be coal capable compared to those designed solely for natural gas use, and the significantly higher fuel costs associated with using natural gas as compared to coal at that time, the Fuel Use Act economically prohibited new EGUs that were coal-capable from using natural gas as the primary fuel. Commenter says the Act was repealed in 1987, but during the time the Fuel Use Act was in effect, electric cooperative generation needs grew substantially. Commenter says, as a consequence about 60 percent of cooperative total baseload electric generation was constructed under Fuel Use Act and is coal based.
Commenter 10952 states, recently the cooperatives are utilizing more electric generation fueled by natural gas for two primary reasons; EPA regulations continue to drive costs of coal-fired generation upwards due to costs of additional emission controls, and lower natural gas prices make EGU natural gas fired generation more affordable. Commenters (9407, 10097, 10952) say, the EPA's supposition in this proposed rulemaking is that the affordability of natural gas for base-load generation will continue, making it the generation of choice over the foreseeable future, thus virtually eliminating any need for future coal-fired generation.
Commenters (9407, 10097, 10952) say, of course requiring new coal-fired EGUs equip with extremely costly and unproven carbon capture technologies, as this proposal does, will all but guarantee none would be built. Commenters say, additionally, with nuclear power generation facing geographical as well as other policy constraining issues, as EPA would have it under this proposal, natural gas would be the sole fuel for practically all new baseload generation. Commenters say, this national energy approach of placing "all your eggs in one basket" is short sighted, high risk and low reward. Commenters say, even if EPA had the regulatory discretion to promulgate a NSPS that virtually mandates a one fuel national energy policy for electric generation, and we believe it does not; it should refrain from doing so for the sake of common sense and rational decision-making.
Commenters (10097 and 10952) state, in this proposal, EPA does not dispute the fact that there are geographic locations where new coal-fired generation of any size or configuration will be unable to meet the proposed NSPS because the infrastructure is not available to allow either EOR or deep well sequestration. Commenters say, in fact EPA believes a NSPS with this geographical constraint is consistent with its regulatory discretion. Commenters say, according to EPA "[c]ertain sources may be precluded from locating in certain areas." Proposal at 1467. Commenters state, in EPA's view it is permissible that under this proposal new coal-fired generation will be impossible in many areas of the country for an indeterminate amount of time. Commenters say thus, this proposal dictates that natural gas generation is the only permissible means of new fossil electric base load generation in large geographic areas throughout the country because it is the only fossil fuel that could technically meet its proposed NSPS. Commenters say, of course should natural gas not be available in some geographic areas, which is the case as pointed out previously in these comments, this proposal allows no options for baseload generation in these geographic areas where coal-based generation requiring CCS is effectively precluded.
Commenter 10952 states, to summarize, many factors requiring coal utilization may well fall within a given new source's purpose and need, in other words its definition. Commenter says, obviously, new generating units may need to be located where needed electric transmission capacity would allow the source's effective contribution to grid reliability but where no or limited natural gas supply capabilities or carbon sequestration infrastructure exist. Commenter says, a source's definition may well include local coal utilization as a means of contributing to the local tax base, economic development, or employment opportunities. Commenter says, in any of these and other circumstances where source definition includes the need to locate the source to fulfill a local need or take advantage of a local resource and that definition include coal utilization, the imposition of the proposed NSPS allowing only CCS where resources are unavailable to do so would be unlawful as requiring source redefinition. Commenter says, for these reasons coupled with this proposal's requirements that prohibit source location where CCS infrastructure is unavailable thus prohibiting new coal-fired EGUs, the proposal is unlawful.
The EPA disagrees and notes that the final standard of performance is not geographically constrained, as so many of the commenters mistakenly maintain.  See generally preamble sections V.H. and I.
The proposed rule is contrary to and unlawfully usurps Congressional intent and power
Commenters (9194, 9487, 9594) believe the proposed rule is contrary to Congressional intent, and exceeds the EPA's authority.
Commenter 9194 states, the selection of CCS technology as BSER is a discretionary decision by EPA and not a requirement of the CAA or a Congressionally-sanctioned policy. Commenter says, the EPA's decision appears arbitrary and targeted at assuring the de facto prohibition of significant new coal-fired generation, closing the door to near-term technological advancements in coal-fired generation. Commenter says, by requiring new coal-fired EGUs to employ CCS prior to its being "adequately demonstrated," EPA will eliminate coal as a future fuel option for electric generating utilities. Commenter says, such a radical departure from past practice and such a far reaching energy policy decision to essentially eliminate coal-fired electric generation in the United States should remain the purview of Congress. Commenter is deeply concerned that EPA will create future guidance to the states for an existing source NSPS under Section 111 that will force the premature closure of our existing coal-fired generating units and fuel switching to natural gas.
Commenter 9487 states, the proposed NSPS will wreak substantial and unwarranted harm on the American public, driving up the cost of energy with little to no corresponding environmental benefit. Commenter says, the proposed rule will effectively and illegally ban the construction of new, modem, low-emission coal-fueled power plants, significantly increase electricity prices, and essentially abandon the future of our most abundant and affordable domestic energy resource. Commenter says, while the NSPS program provides EPA with limited authority to promulgate adequately demonstrated technology based "standards of performance," EPA does not have authority to use the NSPS program to effectively ban new coal-fueled power plants.
Commenter 9487 states, in addition, the proposed rule represents an unprecedented abuse of the NSPS program - and the Clean Air Act in general - to usurp Congressional authority and contravene Congress's manifest commitment to keeping coal as an important component of the nation's electricity mix. Commenter says, the EPA simply has no authority to "enact" new laws, such as a ban on coal-fired plants. Commenter says, if such is to occur, it must happen through measures properly enacted by Congress. Commenter says, indeed, not only is EPA foreclosed from "enacting" a new and different NSPS program, EPA has an affirmative duty under the United States Constitution to "take care that the laws be faithfully executed." (U.S. Constitution Article II, Section 3) Commenter says that is, EPA must assure that it executes the NSPS program precisely and properly as Congress intended.
Commenter 9487 states, in April 2012, EPA estimated that CCS would add about 80% to the cost of a new coal -  fueled power plant. Commenter says, such excess costs may exceed $1 billion for a typically-sized power plant. Commenter says, thus, the proposed rule will have the real world effect of banning new coal-fueled power plants in the U.S. Commenter says, for the reasons expressed above, this is no doubt the intent of the EPA and Administration, but EPA's failure of candor on this point throws all of EPA's analysis into question.
Commenter 9594 states, the EPA is improperly expanding its role by setting national energy policy. Commenter says, the proposed rule is unprecedented in its policy reach, and they believe it exceeds the EPA's authority under the Clean Air Act. Commenter says additionally, because of its de facto ban on certain types of energy facilities, the proposal places EPA in the posture of regulating energy rather than the environment. Commenter says, because the proposal would control not only the emissions of air pollutants, but the choice of fuel and energy that a power generation facility must utilize, EPA is dictating the type of energy sources that may be constructed or operated in the U.S., contrary to Congressional intent and EPA's authority.
This rule faithfully applies the criteria set out by Congress in section 111 (a): to adopt standards of performance for air pollutants based on a best system of emission reduction adequately demonstrated.  The plant utilizing the BSER (actually full CCS, not partial) was recently voted POWER magazine's power plant of the year (August 1, 2015).  The basis for the award echos the findings EPA makes in preamble section V.D.:
   * The technology is highly effective
   * The technology came in on budget
   * Parasitic load is less than anticipated and can be reduced further
   * Many of the expenses of the project were redundancies built in because the plant was first-of-a-kind; successor plants will be less expensive
Congress did not grant the EPA authority to regulate one type of fuel or plant design out of existence
Commenter 10239 states Congress did not grant the EPA authority to regulate one type of fuel or plant design out of existence. Commenter says as a practical matter, the proposed rule would prohibit the construction of new coal-fired EGUs because these units will be unable to achieve, through application of a best system of emissions reduction ("BSER"), the proposed 1,100 lbs CO2/MWh performance standard. Commenter says the EPA seeks to justify this de facto prohibition by asserting that coal-fired EGUs will not be constructed for unrelated economic reasons. See generally RIA, Chapt. 5. Commenter says while there may be some market forces at play, there is no doubt that the EPA's proposal would dictate fuel choices by increasing the barriers to entry into the utility market to the point that new coal-fired EGUs are not economically viable. Commenter says by setting CO2 emissions limits that are more than 25% lower than what the best performing coal-fired EGUs can attain, finalizing the proposed standard would ensure that no new coal-fired EGUs would be built, regardless of any current or future underlying economic conditions.
Commenter 10239 states when enacting the Clean Air Act, Congress did not delegate authority to the EPA to dictate fuel or design choice. Commenter says instead, Section 111 provides a flexible standard that requires the EPA to consider costs, non-air impacts, and "energy requirements." Commenter says the EPA cannot simply ignore these factors because it disagrees with them. Commenter says in fact, a regulation that effectively bans the use of coal would be contrary to Congress' intent when it "designed this section and the entire bill, to encourage and facilitate the increased use of coal ". See, e.g., H. Rep. No. 95-294 at 192. Commenter says policy considerations in favor of eliminating new coal-fired EGUs, such as the President's "Climate Action Plan," are contrary to the text and legislative history of the CAA and do not provide a lawful basis for the EPA's actions. See The President's Climate Acton Plan at 18 (June 2012) ("Going forward, we will promote fuel switching from coal to gas for electricity production"."). Commenter says only Congress may determine whether, as a matter of energy, economic security, or environmental policy, one type of fuel should essentially be banned.
The final standard of performance simply does not ban the use of coal for new capacity.  It may even create a lifeline to the industry.  See public statements of American Electric Power and Alstom cited in preamble section V.I.4, V.F. and RTC 6.  See also statement of SaskPower executive David Jobe, quoted in POWER magazine, that "if coal has a future, this is it".  The standard is achievable, and the CCS technology is already operating successfully at full commercial scale.  The standard imposes costs, but they are similar to those previously adopted in NSPS for this industry, and allow coal to remain a cost-competitive technology for entities seeking an alternative to natural gas which is available at baseload and is dispatchable.  See statement of Alstom Vice President Macnaughton who "presented findings from a recently-conducted cost analysis showing that the cost of electricity generated by coal and natural gas plants equipped with CCS is competitive with other low or no-carbon energy carbon energy sources, such as wind, solar, geothermal, hydro and nuclear."
EPA cannot use Section 111 to regulate the use of one type of fuel or design out of existence
Commenter 10098 states EPA cannot use Section 111 to regulate fuel choice with the practical consequence of regulating one type of fuel and design out of existence. Commenter says the proposed rule amounts to a de facto ban on new coal-fired EGUs because they will not be able to meet the proposed standard for "best system of emissions reduction" (BSER) that is based on the CCS technology that is economically and technically infeasible. Commenter says Congress clearly did not authorize EPA to exercise such sweeping legislative power to impose a de facto ban on an entire category of fuel and source of energy.
Commenter 10098 states their (AFPM and API) members will be harmed by the proposed NSPS rule. Commenter says first, their members will be harmed by the de facto ban on new coal-fired EGUs because they are part of the supply chain for solid-fuel feedstocks and because they are large retail electricity consumers who will be harmed by a lack of energy diversity.
Commenter 10098 states in its Regulatory Impact Analysis (RIA) for the proposed NSPS GHG rule, EPA projects that the rule will have no real effect because the natural gas units covered by the rule will meet the standard with no significant change and because coal-fired units otherwise will not be constructed for economic reasons. Commenter says EPA is incorrect. Commenter says in actuality, if finalized, the proposed rule will itself drive fuel and EGU design choices in the United States. Commenter says the rule would be a de facto ban on the construction of coal-fired EGUs because such units cannot, through application of any best system of emissions reduction (BSER) that satisfies the requirements of Section 111(a)(1), meet the 1,100 lbs CO2/MWH standard EPA proposes to establish here.
Commenter 10098 states the Agency is using Section 111 to make the barriers to entry into the utility market so steep for new coal-fired EGUs that they will not be constructed. Commenter says EPA's approach is contrary to the CAA and the intent of Congress. Commenter states in fact, the legislative history of Section 111 shows that Congress clearly both understood and intended that coal would continue to be a viable fuel for source categories covered by NSPS standards. 
Commenter 10098 states instead, EPA's proposal appears to be part of a concerted effort on the part of the Agency to systematically reduce or eliminate the use of coal, including petcoke, for energy production in the United States. Commenter says such policy concerns expressed by EPA in favor of the proposal have no grounding in the text of Section 111 and do not provide a lawful basis for this action. 
Commenter 10098 states EPA's approach is fundamentally at odds with Congressional intent and is arbitrary and capricious. Commenter says only the legislature should determine whether, as a matter of energy, economic, security, or environmental policy, one type of fuel should essentially be banned. Commenter says, even if Congress were to delegate such authority to ban an entire energy sector to an administrative agency, EPA's mission is to protect the environment not regulate an energy source effectively out of existence.
Commenter 10098 states EPA incorrectly asserts that it is permissible to enact a de facto ban on coal-fired EGUs in areas that lack access to geologic storage sites. Commenter states EPA lacks authority to prohibit coal-fired power plants in areas without EOR or geologic sequestration. Commenter states EPA tacitly accepts that requiring the use of EOR or geologic sequestration would be a de facto prohibition on constructing new coal-fired power plants in areas where sequestration is not reasonably possible by stating that it has the authority, based on the Clean Air Act's legislative history, to ban the use of coal-fired power plants in such areas. 79 Fed. Reg. at 1,466-67. Commenter says reliance on this legislative history is plainly wrong for at least two reasons.
Commenter 10098 states, first the legislative purpose of requiring uniform national standards does not apply to GHGs. Commenter says as the proposed rule explains, the NSPS was created "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"." Commenter says GHGs are global in nature and do not cause or contribute to localized adverse air quality impacts. Commenter says thus, EPA's "pollution haven" justification is not only irrational in light of the unique nature of GHGs, but runs counter to the cited legislative purpose.
Commenter 10098 states under the proposed rule, new coal-fired power plants could only be constructed in states with established EOR operations or well-characterized and suitable geological storage sites. Commenter says the proposed rule is thus contrary to the desire of the Clean Air Act's legislative sponsors, who sought to avoid providing individual states with competitive advantages in the siting of industrial facilities, because it would confer such a competitive advantage to states with viable EOR operations.
Commenter 10098 states as the proposed rule also notes, any given industrial facility could be prohibited from being constructed in a certain area due to the Clean Air Act's attainment provisions under Section 110. 79 Fed. Reg. at 1,466-67 ("[A]n area at or above the NAAQS limits might not have enough room in its airshed to accommodate these new facilities."). Commenter says but there are no National Ambient Air Quality Standards for GHGs, a fact which wholly undercuts EPA's reliance on Section110 here. Commenter says EPA admits that the legislative history that it relies upon was premised on "local air quality concerns," but then states that allotting for itself carte blanche authority to ban the construction of new sources in some or all parts of the country without regard to localized air quality concerns "should not be viewed as inconsistent with congressional intent for Section 111." Commenter says not only does EPA lack a scintilla of legislative history in support of this proposition, its statement that EPA is free to use Section 111 to allow new stationary sources to be constructed "in only certain parts of the country and not other parts," contradicts the proposed rule's proffered "pollution haven" rationale.
Commenter 10098 states not only does EPA concede that it is imposing a de facto ban on coal-fired EGUs, but its rationale for such a ban is baseless. Commenter says it finds no authority in Section 111 itself, no endorsement of its approach in the legislative history, and no precedent in the two inapposite cases cited in the proposed rule. Commenter states the very need to argue that EPA has the authority to prohibit the use of certain types of stationary sources eviscerates its claim that CCS is "adequately demonstrated." Commenter concludes, therefore, EPA should withdraw the rule and either propose a new rulemaking that relies on energy efficiency requirements (in accordance with its own GHG Guidance) or wait until commercial operations validate the use of CCS.
See previous response.  In addition, the commenters are mistaken that the final standard of performance imposes a geographic constraint on new coal capacity due to lack of access to sequestration.  See preamble section V.M. and Geographic Availability TSD showing that there are ample sequestration and EOR sites, plus coal-by-wire opportunities in virtually all areas of the country.  Moreover, there are alternative compliance pathways not involving sequestration should a new coal plant wish to site in an area with the unlikely combination of no sequestration or coal-by-wire access exists, and state prohibitions do not restrict siting.  The EPA also notes that no commenter has presented evidence that such a circumstance might arise.  That is, all comments on this issue have been hypothetical, with no evidence presented of new coal capacity planned for any area, much less one fitting the unlikely set of circumstances just described.  See also preamble V.J. describing how facilities which may qualify as new sources but whose designs were sufficiently advanced are not subject to the final standard of performance.  This provision is hardly consistent with the commenters' claim of `war on coal'.
The proposed NSPS will constitute a de facto ban on new coal-fired EGUs 
Commenters (9197, 10239) state, the proposed NSPS will constitute a de facto ban on new coal-fired EGUs.
Commenter 9197 supports EPA's decision to establish separate standards for coal- and gas-fired generation, but remains concerned that EPA's revised approach to setting performance standards for fossil-fueled boilers and IGCC units still amounts to a de facto ban on new coal-fired generation.
Commenter 10239 says, despite the EPA's unsubstantiated assertion that the proposed rule will have no costs, the proposed standards will significantly harm the Associations' members and the energy and manufacturing sectors as a whole. Commenter says, the proposed standards of performance will constitute a de facto ban on the development of new coal-fired electric generating capacity because CCS cannot be implemented at a commercial scale. Commenter says, prior EPA rules, such as the Mercury Air Transport Rule, have already had a significant effect on existing coal-fired EGUs, with more than 60 gigawatts of capacity scheduled to retire by 2020. Commenter says, as the EPA acknowledges, without the proposed rule, a portion would likely be replaced by new coal-fired EGUs. See 79 Fed. Reg. at 1,443. Commenter says this position is further supported by NERA's analysis, which found a "substantial probability" that economic conditions will, in the near term, favor coal-fired EGUs in some parts of the country. 
Commenter 10239 states eliminating the possibility of new coal-fired EGUs will have a significant detrimental effect on the Associations' members who generate both coal- and petcoke-fired energy and plan to do so in the future and are part of the supply chain for coal and petcoke. Commenter says, thus, the new rule will reduce options for creating new capacity, as well as demand for coal and petcoke, harming everyone in the supply chain for each product. Commenter says, the increased costs and decreased reliability also will harm the Associations' members who must rely upon efficient, cost effective, and reliable electricity in their operations. Commenter adds, the impact of the rule will be felt almost immediately, as EGUs make long-term, strategic decisions regarding future generating capacity. 
Commenter 10239 states, further, eliminating coal-fired EGUs will reduce fuel diversity for baseload energy, creating an increased risk to grid stability and price volatility. Commenter says, while NGCC turbines are expanding, coal, hydroelectric, and nuclear power markets are contracting due in part to regulatory pressure. Commenter says the shift away from a diverse baseload power portfolio and toward an ever increasing reliance on a narrow set of energy sources creates significant risks. Commenter says, changes in market conditions for energy commodities including natural gas, coal, and petcoke raise significant risks. Commenter says, while the Associations have a strong interest in the production of low-cost natural gas, a balanced portfolio is essential to protect against price volatility and changing market conditions. Commenter says, a de facto ban on new coal-fired EGUs would diminish that flexibility. Commenter says, because many of the Associations' members are large retail electricity consumers, they would be directly impacted by service disruptions or price increases. Commenter states, even defensive, preparatory measures to guard against grid instability would require expenditure of valuable resources.
Commenter 10239 states, the EPA cannot simply ignore all of these impacts by suggesting that market forces alone are dictating a shift from coal to natural gas. Commenter says the EPA acknowledges that even in these market conditions, coal-fired EGUs serve important functions for reliability and fuel diversity, and will remain viable even under current price spreads. Commenter says, thus, the EPA is wrong that it is the current cost difference between coal and natural gas that will preclude their future use; instead, the dearth of future coal facilities will arise from the inability of coal-fired EGUs, under any circumstance, to achieve the proposed standard. Commenter says, the EPA cannot hide behind market forces in an attempt to ignore the costs that the proposed rule will impose on the Associations' members.
In response to commenter 10239, The EPA does not acknowledge that, without the proposed rule, a portion of existing plants would likely be replaced by new coal-fired EGUs and we do find such a statement at the cited location in the proposal. In fact, the EPA there stated that " ... even in the absence of this rule, (i) existing and anticipated economic conditions mean that few, if any, solid fossil fuel-fired EGUs will be built in the foreseeable future; and (ii) electricity generators are expected to choose new generation technologies (primarily natural gas combined cycle) that would meet the proposed standards." (79 FR 1433) and we acknowledged that "... for a variety of reasons, some companies may consider coal units that the modeling does not anticipate". We further noted that "[W]e 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." (79 FR 1478) These facts contributed to the agency's decision to withdraw the previous CAA 111(b) proposal and issue a new proposal that specifically proposed separate standards for fossil fuel-fired steam generating EGUs and natural gas-fired stationary combustion turbines.
NSPS is not an appropriate vehicle for establishing a domestic energy policy 
Commenter 10618 states EPA indicates that the proposed rule "reduces uncertainty...for new coal-fired generation." Commenter says the agency is absolutely correct. Commenter says the proposed rule will not just reduce uncertainty, it will eliminate it altogether as the requirements will effectively prohibit the development of new coal-based generation units, and will have little, if any, impact on future natural gas-fired combustion turbine units. Commenter adds admittedly, EPA recognizes that the proposed rule will result in "negligible CO2 emissions changes [or] quantified benefits." 

Commenter 10618 states that the EPA view on the role of coal within a balanced portfolio of energy options has evolved significantly. Commenter says only a few short years ago did EPA prepare a final report as part of "several initiatives to facilitate and incentivize [the] development and deployment of [IGCC] technology." Commenter says EPA noted the following in the forward of that report: 

"Currently, over 50 percent of electricity in the U.S. is generated from coal. Given that coal reserves in the U.S. are estimated to meet our energy needs over the next 250 years, coal is expected to continue to play a major role in the generation of electricity in this country. With dwindling supplies and high prices of natural gas and oil, a large proportion of the new power generation facilities built in the U.S can be expect to use coal as the main fuel... EPA considers integrated gasification combined cycle (IGCC) as one of the most promising technologies in reducing the environmental consequences of generating electricity from coal. EPA has undertaken several initiatives to facilitate and incentivize development and deployment of this technology."

Commenter 10618 states with the proposed rule, EPA has not only eliminated any opportunity for coal "to continue to play a major role in the generation of electricity in this country," but also has eliminated the chance for future coal units to play any role. Commenter says in fact, EPA somewhat disparagingly discusses those who consider energy diversity to include coal by noting that: 

"We are aware of another segment of the industry.....who have indicated a preference for new coal-fired generation to establish or maintain fuel diversity in their generation portfolio because their customers have a 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." 

Commenter 10618 states without question, in the eight years since EPA finalized this report, significant developments within the energy industry have occurred that have dramatically transformed the natural gas and oil industries and that have accelerated the development and use of alternative energy technologies. Commenter says however, EPA should not misconstrue such developments to automatically assume that natural gas is the fuel of the future and will be a readily available substitute to coal- based generation. Commenter says to do so is extremely naive, devalues the benefits of energy diversity, ignores a long history of volatility in energy supply expectations, and is complacent to the ever increasing challenges to the development of natural gas generating units. 

Commenter 10618 gives a brief history of the volatility of the energy sector, starting with nuclear in the 1950's.  Commenter continues, most recently, the development of shale gas techniques has increased the supply and reduced the price of domestic natural gas, which has again shifted new generation development to natural gas processes. Commenter says EPA's confidence that the deployment of natural gas generating units will continue well into the future is evident in the proposed rule where the agency notes that: 

"we recognize that...the higher costs of CCS may tilt the economics against new coal- fired construction. Even in this case the standard would remain valid..., particularly because the basic demand for electricity could still be served by NGCC."

and,

"...even if requiring CCS adds sufficient costs to prevent a new coal-fired plant from constructing in a particular part of the country to due to the 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." 79 Fed. Reg. 1481 (January 8, 2014)

Commenter 10618 states whether or not, and for how long, a strong reliance on natural gas will continue for new generation resources is to be determined. Commenter says a long history of natural gas price volatility and pattern of shifting interest in energy resources suggest great caution against any strategy that devalues the importance of a balanced energy portfolio. Commenter says the proposed rule states that 

"EPA believes that it is appropriate....to set a standard that is robust across a full range of possible futures in the energy and electricity sectors." 79 Fed. Reg. 1434 (January 8, 2014)

Commenter 10618 states the "full range of possible futures" that EPA contemplates is premised solely on the expanded use of natural gas. Commenter says EPA's logic that natural gas units will continue to be a readily available option and can be readily developed as replacement for coal-fired generation is greatly misguided as EPA ignores the mounting pressures on natural gas generation development. Commenter says the press headlines below are just a small sampling of the increased development concerns.

Commenter 10618 states clearly, the development timeline and scope of concerns for natural gas-fired generation resources is becoming and will continue to be more challenging. Commenter says as such, there is no certainty that future natural gas generating units can automatically "be built to serve the electricity demand that the coal-fired power plant would otherwise serve" or that "the present rulemaking does not prevent basic electricity demand from being met." Commenter says nonetheless, EPA references EIA estimates that over 45 GW of new natural gas generation capacity will come online by 2025. Commenter says based on conservative estimates, potential CO2 emissions from this added capacity alone would be over 70 million tonnes per year. Commenter says that EPA states that it is "crucial to take initial steps now to limit GHG emissions from fossil fuel-fired power plants" because these emissions "threatens the American public's health and welfare." Commenter says yet, the agency points out that the proposed rule will only "limit GHG emissions from new sources...to levels consistent with current projections for new fossil fuel-fired generating units." Commenter asks therefore, if the magnitude of these threats is as severe as EPA has stated; if the significance of these risks require immediate reductions in GHG emissions; and if EPA's logic for determining that CCS is available for coal-based generation is equally compelling for NGCC process, then why doesn't EPA require NGCC units to use CCS to reduce the potential 70 million tonnes of new CO2 emissions from these sources as well? Commenter says the answer is two-fold. Commenter says, first, as noted throughout our comments, CCS has not been proven to be technically feasible or adequately demonstrated at a commercial scale for NGCC or coal-based generating units. Commenter says, second, requiring CCS for NGCC units would effectively prohibit the development of any fossil fuel based generation technology; an outcome that would prevent meeting the "basic electricity demand," and would "threaten the American public's health and welfare." 
Commenter 10618 (American Electric Power) states that "with the proposed rule, EPA has not only eliminated any opportunity for coal `to continue to play a major role in the generation of electricity in this country,' but also has eliminated the chance for future coal units to play any role.  The commenter's own public statements are to the contrary, indicating that CCS is critical to the industry's future.  See preamble section V.I.4.  See also the statement of Alstom senior Vice President for Power and Environment Policies Joan Macnaughton's statement (August 4, 2011): "AEP's decision to put Mountaineer II on-hold (sic) is a bellwether to our leaders on the consequences of uncertain climate policy.  The Validation Plant at Mountaineer demonstrated the ability to capture up to 90% of the carbon dioxide from a stream of the plant's emissions.  The technology works.  But without clear policies in place outlining options for cost recovery, power generators are hard-pressed to invest in its continued refinement."  The press release further states that Vice President Macnaughton "presented findings from a recently-conducted cost analysis showing that the cost of electricity generated by coal and natural gas plants equipped with CCS is competitive with other low or no-carbon energy carbon energy sources, such as wind, solar, geothermal, hydro and nuclear."  

See preamble section IX.C.4 for why EPA is not selecting CCS as BSER for new NGCC units. 
Commenter 8954 states with its "Standards of Performance for Greenhouse Gas Emissions from New Stationary Sources: Electric Utility Generating Units", EPA is setting the stage for significantly altering the U.S. energy mix, and indeed, its energy policy. Commenter says these new standards effectively take coal off the table as an option for new generation resources. Commenter says implementation of the rule will reduce American energy diversity and security, stop the development of cleaner coal technologies, and increase the risk of higher electricity prices to consumers and businesses. Commenter says moreover, it will "result in negligible CO2 emissions changes", as the EPA concluded.
Commenter 8954 is gravely concerned about the widespread impacts of the standards as proposed. Commenter believes there are four key areas that must be addressed: 1) the rule's lack of a meaningfully different standard between coal and gas, which will reduce energy competition, diversity, security, and reliability by eliminating coal and increasing natural gas, 2) the impacts on jobs, consumers, and businesses and manufacturers, with the rule causing job loss, increasing energy prices, lowering living standards, and limiting business and manufacturer's ability to compete, 3) the rule's requirement for Carbon Capture and Storage (CCS) and EPA's assumption that CCS is feasible and has been adequately demonstrated, which will serve only to thwart the development of CCS and cleaner coal technology, and 4) the unilateral approach for reducing U.S. carbon emissions absent a global approach and commitments, which will affect our nation's ability to compete internationally and will result in very little impact on global carbon emissions due to other countries greatly increasing coal generation to benefit their citizens and economies. 
Commenter 8954 states in addition to price impacts to consumers, the electric grid reliability issue looms large, especially with the impending shutdown of coal generation plants to comply with EPA MATS rules. Commenter says coal plants were key in enabling electric generators to meet electricity demand and avoid brownouts or blackouts during cold weather this 2013-2014 winter. Commenter says American Electric Power's (AEP) Chairman, President, and CEO Nick Akins has stated that 89% of AEP's generation planned for retirement in 2015 was running in January to meet demand in the PJM electricity region. Commenter says in his recent April 10, 2014 testimony before the Senate Energy and Natural Resources Committee at its hearing on grid reliability and security, Mr. Akins also said, "The weather events experienced this winter provided an early warning about serious issues with electric supply and reliability. PJM was not alone. Many of the Regional Transmission Organizations (RTOs) and Balancing Authorities need to call on Emergency Procedures to ensure reliable operations. This country did not just dodge a bullet - we dodged a cannon ball." Commenter says, further, he testified that AEP plans to retire 6,586 megawatts (nearly one fourth) of its coal generation capacity, with most of those retirements occurring in mid-2015. Commenter says, in PJM, he stated that 12,909 megawatts of capacity is scheduled to retire within two years. Commenter says that Mr. Akins cautioned that capacity replacements may not provide the same level of reliability experienced historically." 
Commenter 8954 states EPA's presumption that the rule drives technology and that costs will decrease over time does not hold up since the rule dramatically tilts the playing field away from new coal plants and will prohibit the construction of new facilities where those technologies would be employed. Commenter asks, why would developers continue down the CCS and clean coal technology path? Commenter says utilities are pushed to make other decisions for generating capacity given the costs and constraints of CCS. Commenter says without ongoing, meaningful governmental support for CCS to propel development beyond first generation technologies and a reasonable timeline to achieve development, too many obstacles and too much uncertainty exists for private developers to move forward. Commenter says Department of Energy (DOE) programs for federal investments in technologies to reduce emissions have played an essential role for decades, and that role should continue for carbon reduction technologies. Commenter says public and private investments to develop mature technologies should be encouraged. Commenter notes however, this EPA rule will have the opposite effect. 
Commenter 8954 states absent a push for new technologies, the U.S. will lose on many fronts. Commenter says other countries not bound by the EPA's rules and regulations will continue to take advantage of coal's low cost and abundance, developing generation fleets without CCS and with far weaker environmental standards for other pollutants. Commenter says they will produce low cost electricity for their consumers and emissions will increase. Commenter says this will overwhelm any efforts by the U.S to reduce carbon emissions or other emissions, and it will diminish the ability of American businesses to compete internationally. Commenter says other countries will also forge ahead with coal technology development and sales around the world. Commenter believes the U.S. will have lost the opportunity to innovate and will cede our global leadership role in developing CCS and other clean coal technologies. 
Commenter 8954 states there is no upside to the rule as written. Commenter believes EPA should go back to the drawing board on BSER. Commenter says the assumptions on which the proposed rule is based are fundamentally flawed and fundamentally skewed against coal. 
Commenter 8954 states in more recent years, U.S. electric utilities have faced a huge number of environmental regulations on all fronts - air, water, and waste - which have contributed to widespread shuttering of existing coal generating capacity. Commenter says according to the American Coalition for Clean Coal Electricity, EPA's rules have contributed to the closure of over 300 existing coal units totaling more than 50,000 megawatts of electric generating capacity.
Commenter adds, the regulatory uncertainty caused by the April 2012 precursor to EPA's currently-proposed GHG rule had the effect of stopping development plans for most of the approximately 15 plants that had received a PSD permit but not begun construction, in spite of the exemption EPA included in that proposed rule. Commenter says when EPA did not propose that rule within a year and instead re-proposed it in 2013 without any exemption for transitional sources, the impact was fully manifested. 
The EPA disagrees that this rule and other EPA rules foreclose the option of building new coal-fired generation. On the contrary, the EPA finds that the final standard of performance can be met by a new SCPC EGU implementing 16% partial CCS at a reasonable cost.  However, the EPA also notes that numerous studies have found that, in the current and projected market context, new coal without CCS is not competitive with NGCC.
Precludes new coal-fired generation and is inconsistent with the President's "all-of-the-above" strategy 
Commenters (1959, 3360, 6871, 6949, 7433, 7977, 8024, 8501, 9002, 9197, 9396, 9472, 9596, 9648, 9655, 10929) state that the proposed rule will preclude new coal-fired generation, and is inconsistent with the President's "all-of-the-above-strategy". 
Commenter 1959 states, since CCS is not commercially viable, with this proposal the Administration is clearly abandoning its "all-of-the-above" energy strategy and embracing an "all-but-one" approach that effectively prevents construction of new coal-based generation.
Commenter (3360, 6949) strongly support a diversified energy mix that evolves with an "all-of- the-above" energy strategy. Commenters say, this proposed rule promotes an "all-but-one" approach that restricts the future use of coal to generate affordable electricity. Commenters say, by limiting the further utilization of coal-fired electricity, the proposed rule could cause economic harm to the families and businesses in our districts.
Commenters (6871, 8024) state, the EPA's proposed rule requiring CCS technology on new coal power plants is unreasonable, and is not supported by the record in this rulemaking or by applicable law.  Commenters say, it will force the nation and electric consumers to a future of higher electricity prices and restricted energy choices. Commenters say, the proposed rule is directly at odds with an "all-of-the-above" energy policy.
Commenter 7433 states, rather than rely on a "one size fits all" approach, Commenter urges the EPA to allow greater flexibility for regions to evaluate their options in complying with future rules and avoid the continued "dash to gas" that this rule appears to mandate. Commenter fully supports the development and use of domestic fuel supplies of all sources, including natural gas. Commenter says, on the federal level, Commenter has been supportive of the "all-of-the-above" energy strategy that holds the promise of ensuring improved long-term energy security, affordability, and reliability. Commenter says, however, the proposed rule may create an unnecessary challenge to electric resource diversity given the fact that coal-fired generation cannot truly be considered a viable generation option in the future. Commenter says, the proposed rule relies heavily on the development of natural gas, reasoning that "in light of a number of economic factors, including the increased availability and significantly lower price of natural gas, energy industry modeling forecasts uniformly predict that few, if any, new coal-fired plants will be built in the foreseeable future." Commenter says, indeed, the EPA's rules will make a perceived zero coal future a self-fulfilling prophecy.
Commenter 7977 states recent winter weather events dramatically demonstrate that there will always be a need and demand for reliable, cost-effective sources of electricity, such as coal. Commenter says, therefore, the narrowing of energy options by this proposed rule is inconsistent with President Obama's all-of-the-above energy strategy and is detrimental to national security and to the economies of Kentucky and the nation.
Commenter 8501 states the EPA has proposed a rule that contradicts President Obama's intentions to diversify energy development in the US by channeling new electric power production towards natural gas, at the expense of new technology development in coal resources (over 80% of Indiana's electricity generation is fueled by coal). Commenter says, instead, the US will hurtle towards natural gas as the predominant source of new electrical generation, which in turn will create economic instability and discourage investment in other fuels, including coal, our nation's most abundant and economically stable fuel option.
Commenter 9002 states, diversity and an all-of-the-above energy strategy is needed for the U.S.  Commenter says, the EPA's environmental policies and regulations cannot inadvertently create a platform where only EGUs are "green power" providers and manufacturing facilities are no longer able to sell green power. Commenter says, manufacturing facilities in the pulp and paper sector generate a significant amount of green power. Commenter, along with others in their sector, sell green power to the grid thereby increasing the availability of renewable energy and providing an additional economic incentive for manufacturers that are able to produce green power. Commenter says, the ability to have this diversity with facilities for renewable energy generation allows for additional renewable energy credits to be available.
Commenter 9197 states, only coal, natural gas, nuclear, and hydroelectric facilities can realistically provide baseload electric power in most areas of the country. Commenter says, because the future expansion of nuclear and hydroelectric power plants is severely limited by siting and permitting requirements, the proposed rule's ban on new coal facilities would commit the country, by operation of law, to complete dependency on a single fuel - natural gas - for meeting demand for new baseload generation. (Although the addition of renewables such as solar and wind can help to address some increase in demand, these sources are inherently non-dispatchable, and so cannot be relied upon to generate baseload electricity.) In Commenter's view, this is neither a wise energy strategy for the United States, nor a good approach to maintaining a healthy economy or supporting American workers - particularly the skilled and highly-trained Boilermaker members, who build and maintain the U.S. fleet of coal-fired power plants.
Commenter 9197 states, rather than moving to a single fuel for all new baseload generation, they urge the EPA to ensure that the proposed rule does not go against the Obama Administration's laudable commitment to supporting all forms of American energy through an "all-of-the-above" energy strategy - a commitment that the President reaffirmed most recently in his State of the Union address. Commenter supports an all-of-the-above approach to energy policy because such an approach helps to ensure an adequate, safe supply of reliable, low-cost electricity to meet our economy's long-term, without exposing the American economy to the risk of supply interruptions or price spikes that have resulted from over-reliance on particular energy sources in the past.
Commenter 9197 states, the proposed ban on new coal generation will compromise the reliability and security of America's electric system. Commenter says, in order to ensure that Americans can continue to depend on low-cost, reliable electricity to power their homes and businesses, the proposed NSPS for power plants must not foreclose utilities and consumers' abilities to generate power from all sources-including from coal. Commenter says, therefore, rather than encouraging the electric industry to move to a single energy source for baseload generation, the EPA should develop environmental regulations that allow all sources of energy to compete with each other on a level playing field. Commenter says, the EPA can help achieve the President's goal of encouraging a diverse "all-of-the-above" mix of American energy resources by ensuring that any rule addressing GHG emissions from power plants does not impose unreasonably stringent restrictions on coal-fueled EGU's - restrictions that could prevent these facilities from contributing to a reliable mix of electric generation in the future.
Commenter 9396 states, the EPA must take local and regional concerns about fuel availability into account when setting the NSPS. The Agency must offer a standard that allows for fuel diversity and does not discriminate against areas of the country without ready access to natural gas, sequestration capability, or the ability to readily utilize other alternatives. As noted, such flexibility is a practical necessity and consistent with President Obama's goal of pursuing an "all of the above" energy strategy in the United States.
Commenter 9472 urges EPA to withdraw the proposal because it is profoundly flawed, biased against the future use of coal to generate electricity, and inconsistent with the President's "all-of-the-above strategy" for domestic energy. Commenter says, the proposal effectively bans future coal-fueled power plants because it requires such plants to use CCS, a technology that is not commercially available or economically viable for coal-fueled power plants. Commenter says banning new coal-fueled power plants is bad energy policy for our nation because it will result in an overreliance on natural gas for new base load generation - a fuel that has a long history of price volatility and deliverability challenges. Commenter says, rather, EPA should adopt an NSPS that keeps coal, our nation's most abundant fossil energy resource, as a fuel option to generate electricity if it makes good economic and business sense to do so. Commenter says EPA should not be picking winners and losers in energy markets. Commenter states, to correct these fatal flaws in the NSPS proposal, they ask that EPA withdraw its proposal, and re-propose a CO2 performance standard with emissions levels based on new high efficiency coal-fueled power plants without CCS. Commenter believes this is required by the Clean Air Act and will allow continued technology development.
Commenter 9596 states, the EPA should regulate CO2 emissions in a manner that does not foreclose future fuel-use options. Commenter says, the Obama Administration has committed itself to an "all-of-the-above" energy strategy of supporting and developing "every source of American-made energy." Commenter says, such an approach can ensure an adequate supply of reliable, low-cost electricity by allowing all energy sources (including coal) to play a role in meeting our Nation's future energy needs. Commenter supports such an approach, and believes that any NSPS EPA develops for power plants must be consistent with this "all-of-the-above" strategy. 
Commenter 9648 states, the EPA states in the preamble that, "... even in the absence of this rule, existing and anticipated economic conditions mean that few, if any, solid fossil-fuel EGUs will be built in the foreseeable future..." Commenter believes that the states and the country must maintain an "all-of-the-above" energy generation mix strategy to allow cost effective, environmentally friendly solutions to its citizens. Commenter says, overreliance on natural gas, particularly during a period of rising gas prices, jeopardizes electricity reliability and economic prosperity for all. Commenter says, common sense pathways must be explored that balances the risk to the economy and the environment. Commenter says, the proposal fails to demonstrate this balance among energy, environmental, economic, and health concerns.
Commenter 9655 states, the proposed regulation is not consistent with an all-of-the-above energy strategy. Commenter says, consumers of energy, whether they are large manufacturers or individual households, benefit greatly from an all-of-the-above energy strategy. Commenter says, diversity of energy supply is not only critical in keeping costs reasonable, it is essential in ensuring steady and reliable streams of electricity to power our factories and heat our homes. Commenter says, for many U.S. businesses that compete in a global economy, energy represents a major input cost that can ultimately determine viability. Commenter says, right now, electricity is an advantage for many U.S. industries in large part because of the abundant and diverse supplies of resources that are collectively keeping energy costs reasonable and supply reliable. Commenter says, however, if regulations such as this proposal take energy options off the table, prices will become more volatile, costs will increase, reliability will be threatened and, ultimately, U.S. firms' viability will be in jeopardy.
Commenter 9655 states, the impact that the January 2014 "polar vortex" had on energy markets demonstrates the importance of a diverse electric generation fleet and how Federal regulations that limit fuel options could threaten the reliability of the nation's electrical grid. Commenter says, in many regions of the country, households depend on natural gas for heat. Commenter says, when temperatures drop, demand for natural gas increases for all consumers, including households, commercial buildings and the electric-power sector. Commenter says, natural gas supplies can be temporarily strained, particularly in regions where there is insufficient pipeline capacity to meet these coinciding spikes in demand. Commenter says, during the 2014 polar vortex, some regions of the country experienced situations where demand for natural gas exceeded supply, which would have led to interruptions of electricity service if other sources of generation (particularly coal-fired generation) were not available to support electricity demand.
Commenter 9655 states, several recently-issued federal regulations [such as the Mercury and Air Toxics Standards (MATS) and Cross-State Air Pollution Rule (CSAPR)]are leading to the closure of a significant number of coal-fired power plants, including many of those that were necessary to maintain reliable electric service this past winter. Commenter says, any shift such as this will only intensify energy diversity concerns and increase electrical grid stress during periods of peak demand. Commenter says, by effectively banning the construction of new coal plants, this proposed rule will only exacerbate these growing grid vulnerabilities. Commenter urges the EPA to carefully consider the potentially dangerous long-term implications of this policy.
Commenter 10929 states, the EPA's economic justification for their proposed coal CO2 performance standard lacks technically sound references. Commenter says, consequently, base load and intermediate load duty cycle service, typical for coal unit operation, may still benefit from construction of new coal that is able to reliably serve customer needs during periods of energy market upsets, making it presumptuous of EPA to assert that natural gas alternatives to coal will dominate future new unit deployment. Commenter says, in turn, system reliability will be at risk absent preservation of a diverse, "all of the above" electricity supply system.
Boundary Dam, POWER magazine's power plant of the year, uses the technology which commenter 1959 calls unproven and non-existent.  This is a graphic indication that standards reflecting use of CCS on slip streams is doable, reliable, and not a back-door means of preventing new coal capacity.
Precludes construction of new coal-fired generation due to costly and unproven CCS 
Commenters (2470, 3360, 6949, 8501, 8966, 8968, 9427, 9597, 9767, 9773, 9777, 10017, 10047, 10050, 10051, 10086, 10098, 10104, 10134, 10240, 10388, 10520, 10552, 10929) believe the proposed rule will preclude the construction of new coal-fired generation due to costly and unproven CCS. 
Commenter 2470 is concerned that under the provisions of the proposed rule, electric utilities will be precluded from constructing coal-fired generation to meet future needs because the standard can be met solely with costly and unproven CCS technology. Commenter believes, however, that utilities should not be precluded from considering coal for future projects due to EPA's decision to set a standard for CO2 based on costly and unproven CCS technology. Commenter says, the proposed standard will significantly increase the cost of new coal capacity. Commenter says, as a result, coal-fired generating units will most likely not be constructed in Florida. Therefore, Commenter is concerned about the potential impact on fuel diversity and compliance costs.
Commenters (3360, 6949) state, given that CCS remains technically and economically infeasible on a large scale, the likelihood that industry will construct any new coal-fired power plants remains highly uncertain for the foreseeable future. Commenters (3360, 10104) say, the Edison Electric Institute estimated that 63 gigawatts of coal-fired power will be retired between 2010 and 2022 due to regulatory, market and other factors. Commenters say, this represented 18.5 percent of America's generating capacity in 2010. Commenters say, the EPA's forthcoming proposed rule on GHG standards for existing power plants may accelerate these closures and require additional plants to close prematurely. Commenters say, without the ability to construct economically new coal plants to account for the closure of existing plants, the proposed rule will have a long-term impact on our energy mix.
Commenter 8501 states, in the most favorable light, the proposed GHG NSPS rule fails to eliminate any uncertainty about coal or promote energy diversity. Commenter says, instead of clarifying the status of coal as EPA purports, the proposed GHG NSPS muddies the future of coal-fired generation even further. Commenter says, because commercial utilization of CCS is highly uncertain due to economic, technological, legal and regulatory issues, the proposed GHG NSPS exacerbates an already uncertain situation for coal. Commenter says, no one will invest in coal generation with so many uncertainties regarding the capabilities of CCS. 
Commenter 8966 firmly believes that the proposed rule, by requiring CCS that is unproven and cost-prohibitive technology at new coal-fired power plants, will decimate the coal industry and coal-fired economies in Pennsylvania. Commenter says, essentially, the proposed rule is a deeply flawed policy that fails to appreciate the magnitude of harm that will be done to the coal industry, the national and state economies, coal utility workers and electric ratepayers with its enactment. Commenter says, by setting an emissions standard that improvidently requires the installation of CCS equipment, the proposal effectively bars the construction of any new coal-fired power plant. Commenter says, this comes at a time when many existing plants are over 50 years old and will soon need to be retired. Commenter says, as a result, tens of thousands of workers in coal-related jobs will likely be laid off due to significant reductions in demand for coal for energy generation.
Commenter 8968 urges the EPA to consider alternatives to the proposed NSPS to limit emissions of CO2 from new fossil fuel-fired electric utility generating units. Commenter says, some of the studies of emerging technologies to capture carbon are very exciting, and Commenter shares EPA's desire to adopt such technologies on a national scale. Commenter does not believe these technologies today are affordable or can be scaled to industrial production. Commenter says, forcing new plants to meet standards that are very difficult, and maybe impossible to meet, will likely have the effect of eliminating the construction of new power plants in the United States.
Commenter 9427 states, the EPA's proposal to require new coal-fueled power plants to deploy the technology CCS would effectively prohibit the construction of any such plants. Commenter says, consequently, the proposal exceeds EPA's authority because such unproven technology is not "adequately demonstrated," because the NSPS program cannot be used to eliminate or threaten the future of an industrial sector, and because Congress clearly intends for coal to continue to maintain an important role in the nation's energy mix.
Commenter 9597 states, as drafted, the proposal would effectively ban construction of new coal-fired EGUs. Commenter says, the EPA's proposal eliminates coal-fired boilers as a future generating asset by way of requiring CCS to be installed; a technology which has yet to be adequately demonstrated at this scale and is hampered with numerous legal issues, such as liability associated with pore space ownership, safety issues with the long distance transport of a super-critical fluid, and long-term concerns surrounding indemnification of any potential release of stored materials. 
Commenter 9773 states, their most significant concern is that EPA, in its proposal, vastly overstates the viability of CCS. Commenter says, at this time, CCS is not achievable for new coal-fired generating units in Wisconsin and throughout the utility sector as a whole. Commenter says, this is because carbon sequestration sites remain vastly unproven by EPA's own admission. Commenter says, further, carbon sequestration sites simply are not available in fourteen states, including Wisconsin. Commenter says, given the lack of CCS viability, the proposed rule would effectively prohibit construction of new coal-fired generation in Wisconsin and many other states. Commenter says, as a result, electric utilities will be forced to continue operating existing coal-fired generating units past their normal lifetimes instead of replacing them with new, more efficient generation. Commenter says, this condition could actually impede the reduction of electric utility CO2 emissions. Commenter says, the EPA should not set an NSPS that prohibits siting new coal generation in this manner.
Commenter 10047 asks, if EPA's analysis shows that no new coal units are planned because of the competitive advantage of natural gas, then how can a coal-fired unit with the added cost of CCS be considered economically feasible?
Commenter 10050 states, the proposed standard would essentially prohibit the construction of new coal-fired power plants by setting a standard that is yet to be demonstrated as achievable.
Commenter 10051 states, the uncertainty and costs related to CCS effectively guarantee that no new coal-fired EGUs will be built in the US until the technology becomes commercially available.
Commenter 10098 states, if adopted, the proposed NSPS for solid fuel-fired EGUs will effectively prohibit any new development of coal-fired electric generating capacity. Commenter says, the proposed NSPS for solid-fuel-fired EGUs will effectively prohibit new development of solid-fuel-fired electric generating capacity because CCS technology is not feasible at a commercial scale. Commenter says, as a result, electric utilities seeking to add baseload capacity will not be able to even consider solid-fuel-fired EGUs as an option and will thus be faced with a limited menu of options to provide additional capacity. Commenter says, by eliminating solid-fuel-fired EGUs as an option for energy generation, EPA's regulations will threaten the continued production of reliable, low-cost energy to consumers and will harm the Associations' members. Commenter says, members who produce and transport petcoke will be harmed because the rule will reduce demand for petcoke as a solid fuel energy feedstock.  Commenter says, members who consume retail electricity will be harmed because by eliminating solid fuel-fired EGUs as an alternative to NGCC, the proposal will reduce energy diversity by eliminating any new solid-fuel fired electric capacity. Commenter says, any potential risk to the consistent and reliable production of energy will, at a minimum, increase operational costs through contingency planning.  Commenter says, thus, it is not the cost of solid fuel-fired EGUs, but their inability, under any circumstance, to achieve the proposed standard that will preclude their use. Commenter says, the EPA cannot hide behind market forces in an attempt to ignore the costs of the proposed standard for coal-fired EGUs.
Commenter 10134 states, the EPA appears to have considered two paths to determine a standard of performance for greenhouse gas emissions from new fossil fuel fired electric generating units. Commenter says, the first was highly efficient generation technologies and efficiency measures, and the second was CCS technologies. Commenter submits that the EPA failed to adequately and holistically evaluate these two options because they ultimately settled on an option (CCS) for new coal-fired generation that has never been demonstrated in a commercial scale application. Commenter says, this decision is contrary to the requirements of the Clean Air Act, and it effectively bans the development of new coal-based electric generation in the United States, without the benefit of meaningful CO2 emission changes or any other quantified benefits.
Commenter 10240 finds CCS as BSER to effectively eliminate the construction of future coal-fired plants and remove from the marketplace any incentive for innovative development of clean coal technologies which will allow for environmentally sound use of this abundant natural resource. 
Commenter 10388 states, as it now stands, the proposal requires new fossil fuel-fired electric generating units (both natural gas-fired and coal-fired) to meet a CO2 emissions rate that can only be achieved using new natural gas combined cycle units or new coal-fired units equipped with CCS technology. Commenter says, since CCS technology is still under development, it is not economical for use on electricity generating units. Commenter says, while the EPA has proposed an extension for coal-fired units to install CCS within the first ten years of operation, the proposed rule will prevent the construction of even the highest-efficiency coal-fired power plants which otherwise comply with stringent federal and state clean air regulations.
Commenter 10520 states, the simple fact of the matter is that the NSPS as proposed would effectively ban the construction of new coal-fired power plants. Commenter says, despite EPA's assertion that CCS technology would allow new coal-fired power plants to meet the standard of 1,100 pounds CO2 per kilowatt hour, the fact is that CCS is an unproven and cost-prohibitive technology that has not been demonstrated on any commercial power plant anywhere in the world.
Commenter 10552 states, the proposed standards inhibit their customers from building new coal-fired EGUs without partial CCS, a technology that is not commercially available.
Commenter 10929 is concerned that the EPA's regulation of new unit CO2 emissions under Clean Air Act, NSPS provisions does so in a manner that precludes the reasonable use of new coal based generation, considering the tenuous nature of the development of CCS technology for large scale, commercial use.
Commenters 2420, 10389, 10520, 10552, 10929 maintain that the standard of performance bans new coal because it is based on a technically undemonstrated technology, unproved at commercial scale.  This is incorrect.  See preamble sections V.D and V.E (should a source wish to pursue pre-combustion CCS, an available compliance alternative).  Nor is a source limited to use of CCS technology to meet the final standard of performance.  Consistent with the request of commenter 8698, the final standard is flexible in that it is achievable by a variety of means, not all of which are based on CCS technology.  (The agency is adopting a less stringent final standard, in part, based on comments urging such flexibility  -  again, not consistent with the claim of `war on coal' or `banning coal').  Issues of legal issues regarding acquiring pore-space or other property rights related to sequestration are discussion in preamble section V.I.5 and V.N.  

Commenter 9773 indicates that the standard would not allow coal capacity in Wisconsin due to lack of sequestration capacity.  As just noted, there are alternative compliance pathways not involving sequestration to meet the final standard of performance.  Second, there is sequestration capacity in the southern part of the state (see Geographic Availability TSD Fig.1.) In addition, as shown in the coal-by-wire chapter of the Geographic Availability TSD, Wisconsin is served by the MISO transmission network.  That is, the state is located in an RTO which provides open access to transmission service and a large set of resources within the RTO to serve load. MISO in fact has a number of coal-fired power plants in areas within geological sequestration. 

Commenter 10134 urges BSER to be highly efficient SCPC.  This is part of the BSER, but not all.  See preamble section V.K. and P.1.

Commenter 10047 asks if coal is non-competitive with NGCC without using CCS, how it can be competitive with CCS.  This misstates EPA's proposal and final rule.  All analysis and market information indicates that coal is not cost-competitive with NGCC, and will not be for the foreseeable future, even as natural gas prices increase.  See RIA chapter 4.  However, new capacity may be added for reasons other than cost, and in that case, the final standard of performance is structured so that coal remains cost-competitive with other baseload non-NGCC dispatchable capacity.  See preamble section V.I.5.
Precludes new coal-fired generation and will discourage development of CCS and other technology innovation
Commenters (7977, 8501, 9196, 9735, 9683, 10395, 10500) state that the proposed rule will preclude new coal-fired generation and will discourage the development of CCS (or advanced coal) technology.
Commenter 7977 states, this regulatory action eliminates coal-fired electric generating units from the competitive marketplace.  Commenter says, the EPA's repeated logic that no coal-fired EGUs are expected to be built in proposing this unattainable standard is counterintuitive to promoting CCS or even advanced coal combustion technologies, such as ultra-supercritical pulverized coal (USCPC). Commenter says, In conjunction with the current market forces of competitive natural gas prices, this standard ensures that no coal technologies, with or without CCS, will be pursued. Commenter says, thus, this rulemaking creates an inherent bias, which will drive fuel switching to natural gas and put the country at a greater risk than a balanced energy profile will provide.
Commenter 8501 states, the EPA claims the benefit of the rule is to clarify that any future coal-fired power plants will be required to utilize CCS and thus eliminate any uncertainty about GHG requirements for future coal-fired generation. Commenter says, by removing this uncertainty, EPA argues, CCS will be seen as an essential aspect of coal-fired power, which will promote further development of CCS technology, which will eventually lead to economical implementation of CCS, which in turn will ultimately assure energy diversity. Commenter says, the EPA, however, could not be more mistaken about the value of the signal it is sending to the marketplace with regard to future coal-fired generation and CCS. Commenter says, instead of providing a path forward for future coal-fired electrical generation, EPA's proposed GHG NSPS simply eliminates coal as a prospective fuel choice for new generation facilities.
Commenter 9196 is concerned that, absent sufficient clarity, the proposed rule could even discourage technology innovation and energy-efficiency projects at existing facilities. Commenter says, this combination of results would result in severe threats to the reliability of the US electricity supply, higher electricity prices for consumers, and would set back the continuing technology and efficiency gains in the power sector.
 Commenter 9735 states, the emission levels required in the proposed rule are currently unattainable on a commercial scale at an affordable level, therefore ensuring that no new, cleaner burning coal plants will be built and CCS technologies will not be advanced. Commenter says, as a result of this federal freeze on the construction of new, cleaner burning, more efficient coal-fired power plants, the full potential for CO2 reductions through CCS will not be realized if we continue to see older plants retired and no new plants constructed. Commenter says, the Energy Information Administration (EIA) reports that by 2040 coal will represent 32% of electric generation, down from 37% in 2012, that is still a significant portion of our generation, especially when you consider that number in context of an increased energy demand overall in this country as the population increases. Commenter says, coal will therefore continue to play a critical role in delivering electricity to families and businesses across the country well into the future.
Commenter 9735 states, considering the unanswered environmental, technical and regulatory issues related to CCS, we should focus our efforts on addressing these barriers instead of creating a rule that effectively blocks CCS development. Commenter believes that CCS must play a role in our national energy infrastructure, as it is one of the only ways to make significant GHG reductions while meeting our energy demand. Commenter concludes, therefore, we must do everything we can to ensure it is implemented in a safe and economically efficient manner. 
Commenter 9683 states that a regulation or law that requires GHG emission limits on power plants will not encourage CCS unless other laws and regulations are concurrently amended to resolve what can be called the "triple jeopardy" circumstance. Commenter says the proposed rule makes possible the circumstance that a coal-fired plant must run for an area to maintain compliance with electric reliability requirements, which are now binding and enforceable by the Federal Energy Regulatory Commission as a result of Section 215 of the Federal Power Act ("FPA"), enacted as part of the Energy Policy Act of 2005; cannot sequester CO2 if the only available geologic sequestration facility is found to be leaking in violation of the Underground Injection Control program; and cannot emit CO2 to the air because of this rule. Commenter asks, what is an operator of a facility covered by a rule supposed to do in such a circumstance? Commenter says rather than subject itself to such jeopardy, project developers may choose other generation options. Commenter says thus, the proposed mandate likely will have a chilling effect, not only on pursuing CCS, but on proceeding with coal-fired generation projects as a general matter.
Commenter 10395 states, the EPA has considered and rejected the only rational and legally permissible option at this time for a coal-fired EGU CO2 NSPS, which is achievable only with optimized and reasonable heat rate efficiencies. Commenter encourages EPA to rethink its rejection of this approach (for coal-based EGUs in general, and for SCPC in particular) if it continues to promulgate CO2 NSPS based on a claim that partial CCS is an available technology for coal-fired EGUs in general, and for SCPC EGUs in particular, at this time. Commenter says, new coal-fueled power plants will need to be built so that less-expensive and more cost-effective second generation CCS demonstrations can occur. Commenter says, because the proposed NSPS will effectively ban new coal-fueled power plants, second generation CCS will likely never be demonstrated in the U.S. Commenter says, while CCS is a promising CO2 emissions control technology, it has not been demonstrated at scale and remains very costly, as shown by the limited and unique circumstances in which the technology has been deployed.
Commenter 10500 believes that this rule will hinder the development of CCS and consequently increase worldwide emissions of carbon dioxide. Commenter says, due to the high cost of CCS, the technology will not be developed, refined, or improved so as to make it technologically or economically viable. Commenter says, even EPA estimates that no coal plants with CCS will be built before 2022 and possibly up to 2040.
See preamble section V.I.4 and other responses in this unit and unit 6.
The proposed rule will delay CO2 emission reductions
Commenters (1681, 7977, 9774) state that the proposed rule will delay CO2 emission reductions and keep existing, less-efficient units operating longer.
Commenter 1681 states, unfortunately, the EPA regulations have already contributed to the closure of 300 existing coal units in 33 states. Commenter says, and recently proposed regulations would ban new, efficient state-of-art coal plants to replace those old plants. Commenter says, using current, market ready technology, a newly constructed coal plant will produce low cost electricity while reducing emissions by up to 90% when compared to the recently closed units.
Commenter 7977 states, preventing the construction of new, more efficient ultra super critical coal-fired generation plants will make it more difficult to retire additional older, less efficient, more expensive to operate plants because of the need to maintain grid reliability 
Commenter 9774 states ultimately, the proposed rule will likely delay utility sector CO2 emission reductions because of the CCS requirement for new coal-fired generation. Commenter says one of the primary compliance options to any utility sector NSPS will be to replace existing generation with new, more efficient generation. Commenter says, however, because new coal generation cannot be constructed under EPA's proposal, utilities are likely to keep existing, less efficient coal generating units operating beyond their normal lifetime. Commenter believes the outcome may very well be that CO2 emissions will not be reduced as rapidly as intended under the rule.
The final standard of performance is based on performance of demonstrated technology and is achievable by a number of means.  The commenters' argument that existing plants will remain open because the new source standard is unachievable thus is not correct.
Precluding new coal-fired generation is good
Commenter 1624 states, that his analysis of the EPA's values suggests they were chosen to allow efficient gas powered units to achieve the set values without any additional effort. Commenter says, the choice seems intended to favor the use of natural gas. Commenter says, the proposed values do not appear to be based on protecting human health or the environment. Commenter says, such limits will encourage the use of natural gas and will most likely prevent another coal fired power plant from being permitted in the US. Commenter concludes, that is good news for the criteria pollutants and mercury.
Commenter 2059 states, this rule will benefit emissions because: (1) Natural gas plants emit 45% less carbon dioxide than coal plants, per kilowatt generated so it rightfully encourages new plants that generate by gas instead of coal. (2) Natural gas plants can augment wind and solar generation, because gas turbines can be spooled up immediately to compensate for lapses in renewable energy generation. Coal generation requires much longer times to boost power. Wind and solar power will be viewed as competition to be resisted by new coal-fired plants. (3) Gas plants produce no soot or mercury health hazards. Coal generation plants do both.
The rule is not structured to reduce emissions of criteria pollutants or Hg.  However, it has the incidental effect of removing additional increments of SO2 if CCS is utilized assuming (against our view) that new non-compliant coal capacity would be built.  See RIA chapter 5; POWER magazine's award to Boundary Dam likewise recognizes that SO2 emissions are reduced due to the need for high purity solvent in the CCS process.
3.7.2 Coal-Fired Generation Can/Cannot Compete With Gas-Fired Combined Cycle Generation
Coal can compete with NGCC
Commenter 9666 states their consultants prepared an independent analysis that disagrees with EPA's conclusions, finding instead that the LCOE from coal-fired and natural gas-fired EGUs, at least for some regions of the U.S., are both about $69-70/MWh (2011 dollar basis). Cichanowicz Economic Analysis. (Attachment 1 to these comments) His analysis found that EPA's erroneous conclusion was driven by three mistakes.
EPA biases its technical analysis by classifying coal-fired EGUs as "high-risk" for financing and NGCC EGUs as "low-risk" for financing purposes. There is no justification for assigning non-equivalent financing charges because new NGCC projects can also be controversial. EPA's discussion of whether CCS at NGCC EGUs constitutes BSER, 79 Fed. Reg, at 1485, opens the door to similar risks for NGCC projects. Many of the same organizations that object to new coal-fired EGUs are objecting to hydraulic fracturing which provides the abundant natural gas that is the underpinning for EPA's natural gas price assumptions. 
EPA's inputs for operating and capital costs failed to account for variability and instead picked the "overnight" capital costs for coal-fired and NGCC EGUs that may not fully reflect present market conditions. Cichanowicz Economic Analysis at 1-2, 13-14. EPA wrongly assumed that the capital cost of coal-fired EGU and NGCC EGU projects can be extrapolated from a single proprietary database, where most inputs appear to be derived from the 2004-2007 timeframe, and escalated to present day market conditions. Both the capital and non-fuel operating costs vary widely, even among six DOE-funded reports, and results have not been peer-reviewed.
EPA conducts what it describes as a sensitivity analysis, but this analysis does not account for the role of market forces, or how overnight capital can vary in the U.S. due to site-specific conditions. Rather, EPA's sensitivity analysis assumes overnight capital cost is essentially identical at all sites, and only varies across the entire country in a well-behaved and predictable manner as determined by changes in construction labor rates.
EPA has more confidence in EIA projections of gas prices than history warrants. As the commenter's consultant report makes very clear, the efforts of the EIA - and for that matter any other fuels forecasting group - over a multi-decade period in predicting natural gas prices is, to put it mildly, inaccurate.. 
Commenter's analysis indicates that coal is competitive in several regions of the U.S. for new EGU projects, with slight revisions to EPA's calculation assumptions. These revisions are not major, and are less than the differences in cost predicted by six DOE-funded reports since 2007.
Most significant are overnight capital and non-fuel operating costs, and natural gas and coal prices. If coal can compete with natural gas across large regions of the U.S., surely there will be many specific applications where coal is the favored fuel for an EGU developer. Such applications may, for example, be at locations near coal supplies or distant from natural gas supplies. 
See response 3.3-16a for response to Cichanowocz appendix.  The commenter's assertion that the NETL studies have never been peer reviewed is false.
EPA's conclusion that coal cannot compete with natural gas for new electric generation is based on an arbitrary set of presumptions
Commenters (9407, 10097, 10952) state that EPA's conclusion that coal cannot compete with natural gas for new electric generation is based on an arbitrary set of presumptions.
Commenter 10952 states natural gas availability and affordability has caused a significant increase in its use to fuel EGU base-load generation over the last several years. Commenter says, but as pointed out above, there are numerous uncertainties associated with its reliance as essentially the sole fossil-fuel resource to provide the Nation's basic electric power needs. Commenter says based on models and associated assumptions referenced in this proposal, EPA concludes there will be little demand for additional coal-based generation over the foreseeable future and thus this proposal has little if any cost impact. Proposal at 1455. Commenter says, the proposal does recognize however that some utility planners may choose to evaluate new generation options based on other factors aside from economic models that EPA relies on in this proposal, such as fuel diversification. Proposal at 1443. Commenters (9407, 10952) say, of course maintaining a diversified electric generation portfolio is justified as a hedge against the unknown. Commenters say, in the case at hand, a national policy that allows for additional new coal-fired generation in lieu of relying exclusively on natural gas for a new EGU would amount to risk aversion based on unpredictable natural gas prices and lack of adequate gas supply where additional baseload generation may need to locate. Commenters say, having a reliable and affordable natural gas supply at a given site where new base-load generation is needed likely presents transportation obstacles and unforeseen impediments outside the control EPA or any other regulatory body. 
Commenters (9407, 10097, 10952) state this proposal essentially ignores common sense concerns associated with virtually ensuring that new coal-based generation cannot be built by proposing a coal-based NSPS that that would make new coal based EGU prohibitively expensive. Commenters say, the EPA's justification for this is twofold; that presently new coal without carbon capture cannot compete with new natural gas EGUs on a cost basis, and that EPA can require an NSPS so long as cost can be accommodated by industry and passed on the consumer. Proposal at 1475. Commenter 10952 first addresses the contention that that new coal-based generation without CCS cannot compete with new natural gas generation on a cost basis presently.
Commenters (10097 and 10952) state, included in these comments as Enclosure 1 (A Critique of the September 2013 Regulatory Impact Analysis: Coal-Fired Power without CCS is competitive with Natural Gas Combined Cycle without CCS, pg 57) is a study prepared by J.E. Cichanowicz to evaluate the proposal's conclusion that new coal-fired SCPC units cannot compete with new base-load NGCC units on a levelized cost of electricity (LCOE) $/MWh basis. Commenter 10952 says, utilizing six DOE studies referenced in the RIA for this rulemaking, EPA concludes an LCOE of $92/MWh for new SCPS EGUs and $59/MWh for new NGCC EGUs. Proposal at 1476 (Table 6). Commenters (9407, 10952) say, based on this LCOE differential EPA surmises that new coal generation cannot compete with new natural gas generation on a cost basis even without considering carbon capture costs. Commenters go on, however, by using a different set of assumptions for capital, financing and fuel costs, all well within the margins of error and variability contained in the studies of which EPA relies, the Cichanowicz study concludes that the LCOE for new SCPC (without carbon capture) can be comparable, indeed virtually equal to that of new NGCC. Commenters depict these findings in graphic form (Levelized Cost of Electricity: SCPC vs. NGCC, Per Sensitivity Analysis).
Commenters (10097 and 10952) state as an initial conclusion the six studies used for EPA's cost comparison analysis were never meant to be utilized for this purpose. Commenters say, the six studies' noted uncertainty range of -15 to +30 percent speaks for itself. Commenters say the study found that performing cost comparisons based on the cost of electricity as opposed to the levelized cost of electricity, LCOE, requires fewer assumptions regarding unit life operating characteristics. Commenters say, as explained above, EPA used the LCOE metric in its cost comparisons. Commenters say, thus, for example, regional differences resulting in lower costs in some geographic areas are not reflected in LCOE calculations. Commenters state, the EPA also inserts a 'climate uncertainty adder'' that serves to drive up the cost of coal-fired EGUs but not NGCC EGUs. Commenters say, the insertion of any 'climate uncertainty adder' involves deriving at nothing more than an arbitrary number, reflecting nothing technical in nature. Commenters note lastly that for coal-fired EGU capital costs, EPA ignored the figure in the most recent 2013 DOE study that presumably would reflect the best estimate and instead used a higher figure derived from an earlier DOE study. Commenters say, these and other factors used in EPA cost methodology serve to increase the projected costs of coal-fired EGUs. Commenters conclude, by using different assumptions, all within the uncertainty ranges in the DOE studies, their analysis demonstrates that coal can compete with natural gas regarding future generation on a cost basis as Figure 2 (Levelized Cost of Electricity: SCPC vs. NGCC, Per Sensitivity Analysis, pg 16) depicts.
See response 3.3-16a.  See also preamble section V.I.2 again documenting reliability of NETL estimates, and their consistency with recent estimates of other private experts and current vendor market quotations.
Proposal treats coal and natural gas inequitably
Commenters (10017, 10092) state that while EPA recognized the need to consider both natural gas and solid fossil fuels, the proposal treats coal and natural gas inequitably, requiring a degree of control on coal plants that has not yet been achieve in practice. Commenter 10017 says that natural gas plants are able to meet the proposed standard for CO2 by building a well-designed plant with technologies presently achievable unlike CCS.
See preamble section IX.C.4 regarding why CCS is not BSER for new NGCC.  Partial post-combustion CCS is a demonstrated technology.  See preamble section V.B.
Dash to gas will not promote climate change goals
Commenter 10046 states, the problem with imposing a technology-forcing mandate on coal alone while leaving gas untouched has been emphasized elsewhere. Commenter says, Professor Richard Macrory, Director of the University College London's Carbon Capture Legal Programme, suggests that if a CCS performance standard is to achieve its technology development and other objectives, then it needs to be applied to both coal and gas, and not to coal alone. Commenter says, in a submission to the U.K. Select Committee on Energy and Climate Change, Professor Macrory opined that it is important to ensure that the design and application of an EPS does not have a perverse or unintended effect and that the performance standard for GHGs applies equally to generating stations or other processes whatever the source of power.
Commenter 10046 states, the position that a CCS mandate imposed only on new coal units will not achieve any advancement in CCS development is a key consideration that EPA wholly fails to address. Commenter says, for EPA's conclusion that a CCS mandate only on new coal units will nevertheless spur development of CCS to be correct, there has to be some evidence that EPA's approach will influence the behavior of power plant developers. Commenter says no such evidence exists and key independent analysts have concluded that EPA's policy will simply encourage developers to build new gas units, which does not promote the development of CCS technology, and in fact impedes it. Commenter says, Bellona made this point in its CCS policy report, asserting that an EPS "in the absence of other supporting policies may be underinvestment, as polluters avoid the development of affected technologies, preferring instead to switch fuel or process with the resulting impacts on energy supply diversity and security."
Commenter 10046 states, the EPA's second fundamental climate change policy error is to cement an unwise "dash to gas." Commenter says, the proposal effectively precludes development of new coal units and impedes development of coal-related CCS technologies. Commenter says, in turn, it does not place any GHG emissions regulatory burden on natural gas EGUs. Commenter says, hence, while the coal industry is precluded from technology development, the gas industry is given no obligations at all because EPA concludes new gas units can meet the standard without doing anything. Commenter says, instead of merely accepting the status quo trend of fuel-switching to natural gas-fired generation, the rule nonsensically mandates this transition without any appreciation of the implications that an unfettered "dash to gas" will have on the Administration's stated climate change objectives. Commenter noted that EPA says that they already consider natural gas to be a low-GHG-emitting fuel and NGCC to be low-emitting technology, natural gas remains a fossil fuel and IEA has specifically argued against an overreliance on natural gas at the expense of CCS development as a mechanism for short term GHG reductions.
Commenter 10046 states, IEA recommends that a "dash to gas" be anchored "in a broader energy policy framework" that embraces more concerted efforts to deploy low-carbon technologies, including CCS. Commenter says, in contrast to IEA's recommendations, EPA is effectively mandating a "dash to gas" by precluding new coal development while also employing a policy to "develop" CCS that IEA calls "not credible."
Commenter 10046 states, the Green Alliance, a London-based environmental think-tank, agrees with IEA's assessment. 
Commenter 10046 states, a recent analysis by the Grantham Research Institute on Climate Change and the Environment similarly concludes that a "dash for gas" only makes sense from a climate change perspective if it is accompanied by a rapid acceleration of CCS "research, development, demonstration and deployment." Commenter says, the Global CCS Institute opens its 2013 report by observing: "Much attention is focused on the environmental benefits of fuel switching from coal- to gas-fired power generation. However, natural gas is not carbon free and, to meet longer term emissions reductions goals, both coal- and gas-fired generating capacity will need to be fitted with CCS." Commenter says, but EPA's decision to mandate CCS on coal plants before it is ready, and to not require that gas units do anything, precludes any development of CCS whatsoever, let alone its acceleration. Commenter says, the EPA is relying on natural gas to provide the answer to the climate change issue, while inhibiting DOE and industry efforts to rapidly develop CCS technology.
Commenter says, it is a stubborn fact that EPA simply refuses to acknowledge: over the past ten years, even if U.S. carbon dioxide emissions had gone to zero, global emissions would still have increased because of the demand for low-cost energy. Commenter says, the simple truth is that banning new coal plants in the United States by imposing an unworkable emissions mandate will not make one bit of difference when it comes to reducing GHG emissions from coal-fired generation. Commenter says, rather than penalizing those who risk capital to reap technological rewards intended to benefit society as a whole, the Obama Administration should focus on driving CCS development in a meaningful way.
Commenter 10046 states that there is no evidence that a regulatory standard reflecting performance of CCS will not have a positive effect on development and deployment of the technology.  The EPA disagrees, see preamble section V.I.4, and the commenter's statement is at odds with public statements from this same industry.  The EPA notes that responsible members of the generating industry itself have indicated that CCS can be a key to a viable future of coal-fired capacity.  See e.g., statement of Alstom senior Vice President for Power and Environment Policies Joan Macnaughton's statement (August 4, 2011): "AEP's decision to put Mountaineer II on-hold (sic) is a bellwether to our leaders on the consequences of uncertain climate policy.  The Validation Plant at Mountaineer demonstrated the ability to capture up to 90% of the carbon dioxide from a stream of the plant's emissions.  The technology works.  But without clear policies in place outlining options for cost recovery, power generators are hard-pressed to invest in its continued refinement."  The press release further states that Vice President Macnaughton "presented findings from a recently-conducted cost analysis showing that the cost of electricity generated by coal and natural gas plants equipped with CCS is competitive with other low or no-carbon energy carbon energy sources, such as wind, solar, geothermal, hydro and nuclear."  Even more directly, Saskpower executive Dave Jobe stated, "if coal power is to have a future, this is it" (POWER magazine, Aug.1, 2015, p. 26). 
3.7.3 Reliance on Coal Generation
Coal is necessary for a balanced energy portfolio 
Commenters (5630, 9193, 9593, 9734, 10048) provide comments regarding the necessity of coal for a balanced energy portfolio.
Commenter 5630 strongly supports a portfolio approach for domestic energy development. Commenter believes a broad energy portfolio will be necessary to meet the needs of manufacturers and businesses in the Great Lakes. Manufacturing industries in particular require a reliable, competitively priced supply of base-load electricity and natural gas to compete in a global economy. Commenter says, the EPA's proposed NSPS propose a carbon dioxide emissions limit on new coal-powered power plants that is about 40% less than is currently possible to achieve with the best technology available. Commenter says, as the nation's leading source of electricity, coal is essential and must be regulated by practical approaches that use sound science and must be shown to be technologically attainable, not overly burdensome on manufacturers and must not disrupt or altogether shut down companies.
Commenter 5630 states, with coal providing roughly 40% of the country's electricity, and an even greater percentage in industrial Great Lakes states, the proposed regulation poses a serious threat to the future of reliable electricity generation and economic output in the United States. Commenter says, it is for this reasons that we oppose the NSPS as written. Commenter says, manufacturing is the heart of the Great Lakes economy and a reliable, competitively priced energy supply is essential to powering our industries, supporting our jobs and maintaining our competitiveness. Commenter says, inexpensive domestic energy sources are a primary factor in the nation's manufacturing resurgence and will be increasingly important to our nation's future manufacturing success. Commenter says, if reducing of greenhouse gas emissions is a critical public policy goal, then that goal should be pursued by funding research to develop technology that is both technically and economically feasible. Commenter says, for that reason, we are strong advocates for the Department of Energy's National Energy Technology Laboratory, whose projects are critical to the efficient, environmentally sustainable development of the nation's abundant coal, oil and natural gas resources.
Commenter 9193 has long been a supporter of alternative and renewable sources of energy. Commenter says, Iowans are leaders in clean sources of energy that emit fewer greenhouse gases - including geothermal, solar panels, methane digesters, wind energy, and biofuels to power farming operations, rural communities, and cities. Commenter says, for example, over the past decade, Iowa utilities and customers have invested heavily in wind energy with both wind farms and local distributed generation. Commenter says, state policies have encouraged wind development to bring Iowa to the point of having the largest share of our energy portfolio coming from wind than any other state Commenter says, Iowa's reliance on coal as an energy source for electricity has dropped from 84% to 62% of electrical generation production between the years 2000 and 2012. Commenter says, wind as a percentage of electric energy generation has risen from 1% to 25% in the same time period. Commenter says, additional wind generation projects are scheduled to be online in the coming years. Commenter says, as a result of state energy policies, Iowa's CO2 production per MWh of electricity generated has declined and is on a downward trend. Commenter says, however, coal remains the dominant fuel source for the generation of electricity in the state of Iowa. Commenter says, while they support the growth of renewable energy production, coal is a cost-effective, reliable fuel source which continues to be important to our state's electric generation portfolio.
Commenter 9593 states that likely future trends in the power market landscape show why new baseload power generation options should not be limited.  Commenter says, many recent forecasts for coal plant retirements, driven in large degree by EPA's programs to regulate non-GHG pollutants, estimate that retirements could reach 60-100 GW by 2020.  Commenter says, this represents between 20% and 35% of the national total coal-fired capacity.  Commenter notes, additional coal plant retirements are possible under the forthcoming 111(d) rule.  Commenter says, further, the U.S. nuclear fleet is aging, few new nuclear power plants are being built or proposed, and the pressure to retire decades-old nuclear plants will increase over time, potentially pulling more of today's baseload capacity out of the energy mix.
Commenter 9593 states without adequately considering the implications, the GHG NSPS proposal would help tilt the nation's energy mix even more dramatically toward natural gas-fired generation.  Commenter says, history provides hard lessons about over-reliance on one fuel.  Commenter says, while we anticipate increased supplies of natural gas and moderate prices for the forseeable future, natural gas has historically been a volatile commodity, with prices reaching over $10/mmBTU for a short time only a few years ago.  Commenter notes in fact, today's increased natural gas supplies and reduced price levels were not expected only a few years ago.
Commenter 9593 states EPA only considered the cost impact of this proposal through the year 2020. Commenter says today, utilities are investing in power generation that will run well into the 2040s. Commenter says, it is risky to implement a policy that relies so strongly on a single fuel for such a long period of time. Commenter notes, the best defense against such risks is a balanced energy portfolio, one that can be sustained through the option to build all types of new power plants. Commenter says, the U.S. sourced its 2013 generation from a diverse portfolio: 39% coal, 27% natural gas, 19% nuclear, 7% hydro, and 7% renewable and other. Commenter's company generation portfolio is similarly diverse, with coal providing 46% of their generation, natural gas 23%, nuclear 11%, renewables and other forms providing 20% in 2013. Commenter states, the proposed GHG NSPS rule would limit the ability of the power sector to reduce consumer risk by maintaining such diverse generating portfolios in the future.
Commenter 9734 states it is simply not feasible for the nation's entire existing coal-fired generating capacity to be transitioned to natural gas. Commenter says, natural gas generation requires transportation from natural gas wells to power plants via an intricate network of interstate pipelines and compressor stations that allow the gas to be constantly pressurized. Commenter says, these requirements raise not only infrastructure concerns but also safety and national security concerns. Commenter says, if a key compressor station were to fail or be targeted in a terrorist attack, the nation's electric grid would be placed in jeopardy. Commenter says, when these natural gas supply requirements are contrasted with coal, which is plentiful in supply, can be stockpiled at a 30-45 day supply, and can be transported via several different methods without the use of interstate pipelines, it makes no practical sense to require wholesale conversions from coal-fired generation to natural gas, particularly in areas of the country that are rich in coal resources and are not located in close proximity to natural gas wells.
Commenter 9734 states, while the current low price of natural gas has contributed to the decline in coal-fired electricity generation and the resurgence of natural gas-fired units, EPA's new regulations are an equally important factor in this trend. Commenter says, in recent years electric utilities have faced a daunting array of environmental regulations on all fronts (air, water, and waste) that have contributed to widespread unit retirements. Commenter says, according to the American Coalition for Clean Coal Electricity, EPA's rules have contributed to the closure of some 300 existing coal-fired units in 33 states. 
Commenter 9734 states, coal-fired generation is essential to ensure energy diversity and to keep electricity prices low. Commenter says, although natural gas prices are currently low, recent data from the EIA shows that natural gas prices have increased by more than 50% since April 2012. Commenter says, EIA's Annual Energy Outlook for 2013 projects that natural gas prices for the electric power sector will continue to increase by about 3.7% each year until 2040, and that total electricity demand will increase about 28% by 2040. Commenter says, these estimates underscore the need for a diverse fuel mix that includes coal to meet these energy demands. Commenter says, recent harsh winter conditions across the country have resulted in severe natural gas price spikes which demonstrate that low gas prices are far from stable.
Commenter 9734 states, indeed, natural gas constraints experienced by all utilities affected by this past winter's "Polar Vortices" underscore these concerns. Commenter says, despite the rapid development of shale resources in the Marcellus region, Kentucky, its neighbor states and eastward were faced with natural gas curtailments, interruptions, supply restrictions, extremely volatile prices upwards of $120 per Dekatherm, and well head "freeze-ups" dangerously restricting or curtailing natural gas power plants. Commenter says, this scenario was exacerbated, if not driven, by extreme home and business heating demands that are fueled by natural gas in the northeast. Commenter says, those electric generating facilities with dual fuel capability were faced with the impracticality of refueling with long lines of fuel oil tanker trucks due to lack of on-site storage for extended periods of heavy usage that were broadly experienced. Commenter says, these events revealed clearly that the natural gas market and infrastructure is simply not able to support the needs of electric generators today, much less the rapid build out expected in the near future as a result of the regulations contemplated by the proposed GHG NSPS.
Commenter 10048 states, this rule effectively establishes a new national energy policy that will significantly hamper electric generation diversity in the United States. Commenter says, at a time when coal-fired units are being shuttered at an unprecedented level, limiting options for new baseload plants could detrimentally impact reliability and drive up consumer costs. Commenter says, the EPA needs to ensure that this rule does not preclude an adequate supply of reliable, affordable electricity, but instead allows for all energy sources - including coal - to play an important role in meeting our nation's future energy needs. Commenter says, the reliance on a diverse portfolio of fuels has been one of the key reasons why the U.S. electric power sector has been successful in providing abundant, reliable, affordable electricity to power the nation's economic growth and high standards of living.
EPA disagrees.  See response at beginning of this Section.
EPA should allow for a continued role for coal use in electricity generation 
Commenters (1959, 3862, 9665) believe the EPA should allow for a continued role for coal in electricity generation.
Commenter 1959 states, there are areas of the country that will require additional electric capacity in the future, but do not have sufficient access to natural gas, do not have suitable sites for CO2 storage or enhanced oil recovery sites, and cannot be supplied wholesale power reliably through the existing transmission grid. Commenter says, it is critical that new coal remain an economically viable option for such locations. Commenter asks, how will EPA reconcile elimination of new coal-fired capacity in these situations?
Commenter 3862, states, a shift in fuel prices in the future could necessitate additional coal use for our country. 
Commenter 9665 states the EPA's regulatory decisions should promote the increased use of natural gas-fired power, while also allowing for a continued role for coal. Commenter says natural gas is an abundant and reliable domestic resource, which can be used to generate power in an extremely efficient manner. Commenter adds, moreover, gas turbines are an ideal match with renewable energy sources, such as wind and solar power. Commenter says at the same time, coal continues to be a vital and viable component of our nation's energy mix, and the latest technology in coal is cleaner and more adaptable than ever before. 
Commenter 9665 states that the EPA should allow for a continued role for coal use in electricity generation. Commenter says while the proposed rule appropriately recognizes the increasing role that natural gas will play in the nation's electricity production and its lower carbon emission profile, it is important for EPA to (1) recognize that coal remains an abundant natural resource in the U.S. that can be used in an environmentally-sound manner, and (2) adopt reasonably achievable emissions standards for new fossil fuel-fired boilers and IGCC units. Commenter says as of January 1, 2013, EIA estimated that the demonstrated reserve base (DRB) for coal is 481 billion short tons. Commenter says U.S. coal resources are larger than existing natural gas and oil resources, based on total British thermal units (BTU). Commenter says as is recognized in the President's "all of the above" energy policy, it is important for EPA to allow for coal to remain a vital part of our country's fuel mix.

Commenter 9665 states that his company has made substantial investments to make IGCC commercially available. Commenter says IGCC systems utilizing GE gasification technology have been successfully deployed at 19 commercial facilities. Commenter notes IGCC systems are more efficient and emit less pollution than traditional coal-fired units. Commenter says according to EPA's Regulatory Impact Analysis, IGCC units emit 99 percent less SO2 and significantly less NOx and hazardous air pollutants, such as mercury, than supercritical pulverized coal plants. Commenter says IGCC units also emit significantly less CO2 than other coal-based technologies. Commenter says in the preamble to the proposed rule, EPA notes that new IGCC units emit approximately 1,450 lb. CO2/MWh, which is approximately 25 percent less than the CO2 emissions from an efficient subcritical pulverized coal-fired boiler. Commenter states finally, IGCC units also are well suited for carbon capture technology, and can be constructed to be carbon capture ready.
In response to commenter 9665, use of IGCC with natural gas co-firing is a potential compliance pathway to meet the promulgated standard of performance.  This is another instance of how the rule is structured to preserve a role for coal.  
Economic impacts without coal as an option 
Commenters (8955, 8966, 9033, 9775) comment on the economic impacts without coal as an option.
Commenter 8955 is concerned that the one-size-fits-all approach, often characteristic to EPA rulemaking, for regulating GHGs may be short-sighted, as the EPA stated that "existing and anticipated economic conditions mean that few, if any, solid fossil fuel-fired EGUs will be built in the foreseeable future". Commenter suggests that the standards set for new coal-fired EGUs are not set to make them so cost prohibitive that we only use natural gas as the fuel for new EGUs for the rest of time. Commenter says, by doing so, the economic and social impacts to our constituents and Wyoming itself would be enormous and long lasting.
Commenter 8966 states, reductions in coal-based energy generation are expected to have considerable ripple effects well beyond the industry. Commenter says, as has already been observed in several states, communities whose vitality depends on the coal industry will become economically depressed. Commenter says, availability of relatively cheap energy will be reduced, particularly hurting the poor, who spend a disproportionate amount of income on energy. Commenter says, further, because coal generates such a large portion of electricity in the U.S., many regional authorities predict disruptions in service, hurting consumers and businesses. Commenter says, therefore, while the proposed rule on its face only affects construction of new plants, in reality, it will do great harm to the coal industry and the U.S. economy. Commenter says, to protect the livelihood of thousands of coal workers and their families, as well as their communities and the overall economy, Commenter urges the EPA to withdraw and reconsider its proposed rule.
Commenter 9033 states with no new coal power generation being built it's our view that this presents a real threat to the US economy both in terms of employment in the industries that build and supply materials for coal plants, as well as coal mining, transportation and maintaining the necessary skill sets to design, build and operate such plants through a period of 10 or more years of inactivity. Commenter adds coal has always been the fuel that balanced electric prices through price spikes of gas and other market conditions.
Commenter 9775 states, by effectively eliminating coal, one of Utah's and our nation's most affordable and abundant fuel sources, for use in new power plants, this regulation will likely result in more volatile and expensive electricity prices. Commenter says, the EPA does not show, however, that these regulations will reduce overall greenhouse gas emissions rather than merely shifting power production and related emissions to unregulated entities in the U.S. and abroad. Commenter says, while new U.S. coal-fired power plants would likely be cleaner and more efficient than foreign alternatives, the EPA's proposed rule would make these foreign power producers more attractive to industry. Commenter says, this would result in the EPA shifting many of the economic advantages of coal to foreign markets without achieving the stated goal of reducing greenhouse gas emissions.
Commenter 9775 states, low, stable energy prices and reliable power are key drivers for Utah's economy, and coal provides a significant portion of Utah's base load electricity. Commenter says, in addition, our coal industry is one of the most important industries in the state, employing thousands and supporting significant economic activity, particularly in rural areas. Commenter says, recent environmental upgrades and financial investment have made existing Utah coal plants very clean and efficient. Commenter says, new plants would be even more clean and efficient. Commenter says, these developments and other technological improvements would continue to reduce emissions in the absence of the costly and unjustified new regulations.
Commenter 9775 states, these expensive, inflexible, and ineffective regulations will result in higher electricity prices, which will negatively impact all aspects of Utah's economy. Commenter says, in particular, industrial energy users, who provide tens of thousands of high-paying technical jobs in Utah, will pay significantly more for power, and will be less able to compete against unregulated producers in global markets. Commenter says, there will also be significant detrimental fiscal impacts to local, state, and federal government, including Utah's public schools, if the mining and utilization of coal is curtailed or stopped. Commenter says, effectively excluding coal from our nation's future energy mix will have significant and long-term negative consequences for our nation's security and economic health, including for families and businesses nationwide, all of which will be forced to bear artificially high energy prices.
The premise of these comments is mistaken.  The final rule preserves a place for coal.  As SaskPower Executive Dave Jobe recently stated, "As Dave Jobe said, "if coal power is to have a future, this is it." 
National natural gas infrastructure may be inadequate
Commenters (8501, 9396, 9597) provide comment on the potential inadequacy of the national natural gas infrastructure.
Commenter 8501 states, fuel needs to be near the electric generating facilities which are connected to transmission lines. Commenter says, unlike coal, which can be transported by rail, barge, conveyor, and truck, natural gas can be moved from its source to the generating facility only by pipeline. Commenter says currently there is a deficiency in pipeline capacity to supply natural gas to the sources that would need to use the fuel to generate electricity. Commenter says furthermore, there is great risk that such new capacity will never be constructed. Commenter says, investors won't invest in new pipeline capacity unless gas suppliers will make long term commitments regarding gas shipments. Commenter says, suppliers are currently reluctant to make commitments under current market scenarios because prices are low (in many cases below production costs) and there is a fear of significant natural gas price increases created by increased demand and potentially tighter supply caused by power generators needing more natural gas. Commenter says, in contrast, coal supplies are stable and storable.
Commenter 9396 recommends for background analysis an Aspen Institute Report developed for the American Public Power Association entitled "Implications of Greater Reliance on Natural Gas for Electric Generation." Commenter says, the report details the implications of limited availability and capacity of natural gas infrastructure near existing generation sites that might be candidates for repowering in the future. Commenter says, in these areas that lack ready access to natural gas supplies, the proposed NSPS would effectively preclude the construction of any fossil fuel-fired EGUs until such time as the cost of fossil fuel generation with partial CCS attains the nth-of-kind cost expectations of EPA or a new natural gas pipeline and storage infrastructure has been put into place. Commenter says, however, in some areas, even CCS would not be an option if access to sites suitable for geologic sequestration impaired by factors such as geographic unsuitability, liability, mineral rights, or other reasons. 
Commenter 9396 states, during the most recent "polar vortex" utilities in the Midwest experienced weather extremes that created a number of systemic risks to the electric grid. Commenter says, notably, during the period of Monday, January 6th to Wednesday January 8th PJM set a new record level of demand for electricity keeping the lights on only by reliance on demand reduction based on mandatory and voluntary curtailment. Commenter says, during this period, 50,000MW of capacity was offline and gas generation units not operating as a result of inability to secure natural gas supply due to pipeline constraints jumped a shocking 320% to 9160MW during the event. Commenter says, spot prices for natural gas in the Mid-Atlantic in January surged almost 340 percent to $45 per million British thermal units, and gas prices in New York City rose more than 780 percent. Commenter says, as a result of the high fuel costs, the price of electricity in the region shot up to $857 per MWh on January 22. 
Commenter 9396 states, pipeline capacity and natural gas supply remain a serious policy obstacle to NGCC development that is under discussion at the FERC and within the industry but to date remains unresolved. Commenter says, PJM has narrowly avoided rolling blackouts in 2014 but future retirements of existing units jeopardize future reliability. Commenter says, American Electric Power (AEP) reports that 89% of the roughly 6000MW of capacity scheduled for closure due to environmental regulations were operating during the polar vortex. Commenter says, PJM utilities weren't alone: the Tennessee Valley Authority (TVA) had to shut power off at Murray State University in order to avoid regional blackouts and South Carolina experienced rolling brownouts as the local utility, SCE&G, was unable to keep up with demand.
Commenter 9597 states, an additional concern with the proposal's practical effect of banning new coal-fired EGUs is that the national natural gas infrastructure may not currently be robust enough to support whole scale fuel switching. Commenter says, the EPA cannot assume that all sites are adequately supplied to a level that would support intermediate and baseload EGUs.
EPA does not agree with these concerns.  The natural gas infrastructure issues are entirely manageable under this rule.  Natural gas pipeline capacity has historically expanded to meet the needs of new natural gas generation capacity, and the same developments will happen in the future.  This is particularly true in the case of comments where additional capacity will be required to meet the requirements of generation already connected to the pipeline system.  It is also true for areas not yet connected to the natural gas pipeline system.  Thus, the normal expansion process will address most cases where additional infrastructure is needed.  In is also important to recognize that other areas that are not connected to the pipeline network are connected to the electric transmission network and can receive electricity generated by natural gas; where necessary, the electricity transmission system, like the natural gas pipeline system, has historically expanded to fill the needs of new load as well as new generation.  In the near term, there should be few additional infrastructure needs, as this rule does not affect the continued operation of any existing sources.  In the longer term, as the generating fleet turns over, much of the existing fossil generating will remain and continue to be diverse, while the normal infrastructure development noted above can accommodate much of the new demand.  Moreover, much of the new demand need not be met by natural gas, but by various forms of new renewable energy.  The new sources are becoming more competitive and are already serving significant load previously served by older generation sources.  Many studies demonstrate the ability for these sources to serve as much as 30 percent of the total load in the US.

Also, as new combined cycle gas units operate more in a baseload capacity, they are better able to support the long term contracting process because they can expect to have a steady stream of revenue to support the regular payments under such contracts.  This increased ability to support the longer term revenue stream also means that operators of NGCC facilities will provide greater support for the use of firm natural gas contracts.  These firm contracts will, in turn, support increased pipeline capacity to ensure the a reliable supply of gas where needed to forestall a recurrence of the "Polar Vortex" like winter emergency periods where natural gas and electricity peak demands intersect.  .  The combination of firm contracts and risk management through market mechanisms will provide the needed basis for managing natural gas pricing and delivery.  For these reasons, EPA believes the rule will aid in easing industry concerns of both natural gas price fluctuations and supply
A wholesale transition from coal to natural gas is not feasible
Commenter 9382 states, a wholesale transition from coal to natural gas is not feasible. Commenter says, it is simply not feasible for the nation's entire existing coal-fired generating capacity to be transitioned to natural gas. Commenter says, when natural gas supply requirements are contrasted with coal which is plentiful in supply, can be stockpiled for several months of supply, and can be transported via several different methods without the use of interstate pipelines, it makes no sense to require wholesale conversions from coal-fired generation to natural gas, particularly in areas of the country that are rich in coal resources and are not located in close proximity to natural gas wells.

Commenter 9382 states, while the current low price of natural gas has contributed to the decline in coal-fired electricity generation and the resurgence of natural gas-fired units, EPA's new regulations are an equally important factor in this trend. Commenter says, in recent years electric utilities have faced a daunting array of environmental regulations on all fronts - air, water, and waste -that have contributed to widespread unit retirements. Commenter says, according to the American Coalition for Clean Coal Electricity, EPA's rules have contributed to the closure of some 300 existing coal-fired units in 33 states. 

Commenter 9382 states, coal-fired generation is essential to ensure energy diversity and to keep electricity prices low. Commenter says, although natural gas prices are currently low, recent data from the United States Energy Information Administration ("EIA") shows that natural gas prices have increased by more than 50% since April 2012. Commenter says, EIA's Annual Energy Outlook for 2013 projects that natural gas prices for the electric power sector will continue to increase by about 3.7% each year until 2040, and that total electricity demand will increase by 28% by 2040. Commenter says, these estimates underscore the need for a diverse fuel mix that includes coal to meet these energy demands. Commenter says, natural gas constraints experienced by utilities this winter underscore these concerns.

Commenter 9382 states, the ongoing increases in natural gas prices should be viewed through a historical lens. Commenter says, the two units at the Merom Generating Station, which represent over 80% of Hoosier Energy's owned coal generation, were constructed during the oil embargo and Fuel Use Act years of 1973-1987 when Congress banned the use of natural gas for generating electricity. Commenter says, the EPA's proposal now does opposite by effectively banning new coal-fired generation. Commenter says, the option to construct new coal-fired generation should not be foreclosed by this rulemaking. Commenter says, fuel diversity, including new coal-fired generation, is vital to our nation's economy and national security.
EPA disagrees with this comment.  As EPA has emphasized in response to previous comments, this rule does not constitute a moving away from energy diversity and coal will remain a significant part of the energy mix. SaskPower executive Dave Jobe stated "if coal is to have a future, this is it".  AEP executives made similar statements with regard to the successful Mountaineer demonstration retrofit project.  See preamble section V.I.4.
Coal is not needed 
Commenter 1975 states, the proposed standards are on track with current trends and technologies in power plants, and reflect the continuing decline in applications for new coal-fired power plants. Commenter says, these regulations represent an important shift in support from coal and other fossil fuels that pose serious national security, environmental and public health risks.  
Commenter 9514 states looking ahead, forecasts indicate that with the possible exception of a small number of projects already under development, new coal-fired generating capacity will neither be needed nor economically viable over at least the next decade. Commenter notes for example, EIA predicts in its Annual Energy Outlook 2014 Early Release Overview that total domestic coal-fired capacity will decrease by over 15 percent from 2012 to 2040. Commenter says, EIA attributes this trend to slower growth in electricity demand, competition from renewable energy and natural gas, and economic changes resulting from more stringent environmental regulations. Commenter says, similarly, NERC anticipates that 31.5 GW of net coal-fired capacity will retire by 2023. Commenter adds that EPA notes in the preamble to the proposed rule that as coal-fired plants retire, current power sector economics suggest that they will likely be replaced with new natural gas combined cycle plants (NGCCs) also known as combined cycle gas turbines, (CCGTs) and with zero-emitting wind, solar, and energy efficiency resources.
These comments are consistent with EPA's analysis.
