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.