Commenter 9765 continues that they  disagree with the assessment that each coal-fired facility built in the future will be able to implement partial CCS in a manner that is both environmentally sound and not cost prohibitive to rate payers. They state that in this respect, the EPA did not consider fully the breadth and scope of the factors Congress provided for making a BSER determination. Commenter remarks that while the EPA gives ranges in its LCOE assessment for supercritical pulverized coal (SCPC) and integrated gasification combined cycle (IOCC) facilities, it is not possible for the EPA to have considered all costs associated with the implementation of partial CCS. The reason such a cost analysis is not possible is that the costs associated with each facility employing CCS technology require consideration of site-specific information. For instance, CCS is not one solitary defined piece of equipment that an operator can install on a facility. Rather, CCS is, at a minimum, a three-step process. Thus, an operator must combine three or more types of technology to make one CCS system work. Commenter 9765 concludes that because of this complexity, the EPA must first conduct a cost analysis on all available capture methods, including pre-combustion, post-combustion, and oxycombustion techniques. Next, the EPA must address costs associated with the compression and transportation of CO2, This analysis will vary significantly with each location and requires the EPA to consider many factors, including "availability and acquisition of rights-of-way for new pipelines, capital costs, operating costs, length and diameter of pipeline, terrain, flow rate of CO2, and the number of sources utilizing the pipeline." After consideration of these variables, the EPA must then assess costs associated with storage or sequestration. Again, the site-specific characteristics, such as the distance of a plant from an adequate sequestration location or EOR project, will have a significant bearing on cost estimates. Additionally, closure and post-closure costs, monitoring costs, plug and abandon costs, and ongoing financial responsibility must be assessed if sequestration is chosen, which will likely vary with the size, depth, and type of formation selected. Commenter further concludes that given the multitude of site-specific factors involved in planning for CCS technology, and the extremely site-specific nature of each facility, it is inappropriate to claim EPA can conduct an adequate cost analysis of imposing CCS technology on all new coal-fired power plants across the country. This rule is not as simple as proposing the addition of a safety switch or new air filter; it requires innumerable nuanced calculations that the EPA cannot possibly calculate for every facility absent site-specific facts. The EPA cannot claim to create a national rule meant to address any situation in which a coal-fired power plant will be built, while ignoring nearly every variable that a utility company would consider when choosing to build.
The EPA is not considering EOR revenues in its determination that costs of the standard of performance are reasonable and not exorbitant.  Regarding site-specific costs, the EPA made reasonable, representative cost estimates, and specifically included costs for all of the items related to local property rights (rights of way, land acquisition, pore acquisition rights, etc.) mentioned by commenters.  See preamble section V.I.5.  The EPA notes that the costs related to sequestration were developed for the Class VI rule, a rule that is already in effect and was not challenged in court.  Moreover, there are compliance alternatives available under the final rule which do not raise these site-specific concerns, since they do not involve sequestration.
Carbon sequestration costs and risks
Commenter 9765 states the EPA must provide an analysis of the technical, economic, and legal issues related to geologic sequestration if sequestration is to be included in the IPM model. Based on Wyoming's experience as a leader in addressing collateral issues associated with carbon sequestration, the framework that is required to ensure the long-term viability of carbon storage must be determined at the state and local level in the absence of a federal, unified framework. Such local efforts involve notable resource investments in time and personnel, and can conceivably have the same or larger impact on the overall viability of any project involving carbon storage. The EPA, however, did not evaluate these investments and costs prior to issuance of the Proposed Rule.  Further, the EPA did not provide a detailed analysis of the accessibility to CO2 pipeline infrastructure for EOR.
Commenter 9765 continues the complexity of the issue shows that the EPA's predictions are extremely speculative, especially when forecasting the long-range effects of this technology mandate. As described in detail in a report to the Wyoming State Legislature, considerable financial risks and costs persist throughout the life of a CO2 storage site, beginning with siting, permitting, and construction, and continuing on through operation, post-closure, and long-term stewardship of the facility. Post-closure would require a facility to actively monitor its site to make sure the site is safe and secure, the CO2 plume has stabilized, and the site could be safely abandoned. Long-term stewardship would require monitoring and continued financial risk for a lengthy or possibly indefinite period. Commenter adds that EPA's Proposed Rule does not address the management of displaced fluids from carbon storage. Injected CO2 will displace fluids from the storage area. An operator must transport those fluids to avoid disruption of confining spaces and destruction of the integrity of the storage system. Fluid management would likely include water treatment and management at the surface, which would also be costly. These costs of monitoring and water treatment would pale in comparison to the financial risks associated with induced seismicity, which could lead to subsidence or uplift, causing property or infrastructure damage, as well as possible impacts to water quality. In addition, plume leakage or migration into recoverable mineral zones could lead to mineral rights infringement and legal costs associated with settling those disputes. On top of all this uncertainty, the EPA fails to address the differences in regulation of oil and gas between different states.
Commenter 9765 continues  that they consider the Proposed Rule inadequate in addressing the costs and the potential financial and legal risks associated with carbon capture and storage, and urges the EPA to conduct a full accounting and consideration of these risks and costs before carbon storage is a required control system in this or any other rule.
The EPA has in fact thoroughly considered the technical, economic and legal issues related to CO2 transportation and geologic sequestration. For transport, costs reflect pipeline capital costs, related capital expenditures, and O&M costs. Sequestration cost estimates reflect the cost of site screening and evaluation, the cost of injection wells, the cost of injection equipment, operation and maintenance costs, pore volume acquisition expense, and long term liability protection. These sequestration costs reflect the regulatory requirements of the Underground Injection Control Class VI program and GHGRP subpart RR for geologic sequestration of CO2 in deep saline formations.

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

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

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

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

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

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

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

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

Commenter 9777 states even if it were economically viable, which it is not, the CCS process is a water intensive process and sufficient quantities of additional water do not exist in Texas to provide either the necessary increased withdrawals or consumption.

Commenter 10880 states the EPA did not adequately consider the environmental consequences of the proposed rule. The proposed rule will result in increased natural gas production, and with that, increased exploration, development, production and transportation of natural gas to supply the power sector. The increased land use and other environmental impacts of increased natural gas drilling, natural gas and CO2 pipeline construction and sequestration storage and injection sites were not adequately considered. The IPCC estimates methane as 34 times stronger a heat trapping gas than CO2. The EPA did not adequately consider the methane emissions, increased impact to groundwater, and increased water use from added natural gas well fields.

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

In addition, EPA strongly disagrees with comments asserting disagreement about whether human activities and greenhouse gas emissions are the primary driver of recent climate change.  See the 2009 Endangerment Finding as well as response to comments 4.1-8 and RIA Chapter 3 for additional discussion.
Outside of the agency's regulatory discretion to define reasonable cost