Commenter 8966 states many operators of CCS systems will also be required to transport captured supercritical carbon to a storage site. Depending on the proximity of the plant to a suitable geologic formation, transport costs may range from $2.50 to $5/ton CO2 per 100 km, depending on the pipeline's mass flow rate and surrounding terrain. While these costs may be marginal for operators in close proximity to a suitable site, they can quickly balloon for plants situated in an area several hundred miles from such a formation, amounting to tens of millions of dollars annually. Thus, enactment of the rule would inevitably impose exorbitant costs on plant operators and the coal industry, contrary to law.

Commenter 9780 states EPA relies on data (in its RIA analysis Table 5.5) that show partial CCS increases costs for a supercritical pulverized coal (SCPC) unit by 34.6 percent for capital, 28.5 percent for fixed operations and maintenance (O&M), and 36.4 percent for variable O&M. By the Portland Cement standard, these cost increases are not reasonable.
See preamble Section V.H where the EPA shows that the standard of performance is reasonable, considering costs, on both a per-plant and national basis.
Sector-wide versus individual plant basis for cost impacts
Commenter 9513 states although the use of CCS technology will incur some additional cost at the individual unit, given the projected number of new coal plants that would be built, with or without promulgation of the regulation, the CCS requirement will not have a significant impact on electricity rates, either regionally or nationally. EPA is correct in its determination that, under the CAA, the assessment of cost impacts is to be made on a sector-wide basis, rather than on an individual plant basis.
See previous response.
Broader geographic scale costing yields more lenient standards
Commenter 9780 states the court in Costle specifically rejected arguments by environmental group petitioners that EPA must base section 111 standards on an assumption that all plants would use the system of emissions reduction corresponding to the "maximum technologically feasible level of control." 657 F.2d at 329 Instead, the court upheld EPA's issuance of a variable percentage reduction standard based on EPA's determination that a less stringent, variable standard "would achieve virtually the same emission reductions at a national level as a uniform approach but at substantially lower costs." In other words, the Costle decision only affirmed EPA's consideration of total reductions and cost as a rationale for selecting a more lenient emissions standard than the one preferred by environmental group petitioners.
Commenter 9780 states the Agency implies that a standard based on partial CCS is required "regardless of feasibility and cost" because it will result in substantially greater reductions than would result if new fossil fuel-based power plants did not use CCS. Yet, the Agency also insists that the additional costs from the proposed standards "will, on a nationwide basis, be small because no more than a few new coal-based projects are expected." 79 Fed. Reg. at 1480. Assuming EPA is correct that costs will be low because only a few new coal-based plants would be built anyway, then EPA has no basis for also arguing that a meaningful additional amount of total emissions reductions would result from requiring partial CCS instead of basing the section 111 GHG standards on highly-efficient coal-based generation technology.
The final standard of performance is justified based on an assessment of costs on an individual plant basis, as well as sector  - wide.  The implication commenter 9780 sees is not correct.  It is not EPA's position that reduced emissions can, a priori, eliminate consideration of cost in determining whether a system of emission reduction is "adequately demonstrated" for purposes of section 111 (a).
Use current costs
Commenter 10870 states the cost of the Proposed Rule will have harmful impacts upon North Dakota and the regional and national economies, and commenter adds that EPA is interpreting the CAA in such a way that justifies the current high costs of installing CCS systems on new coal units, for example the position that EPA is not restricted to assessing costs on a source-by-source basis, but may consider costs at the industry or national level-where the cost barriers to CCS are less apparent, and that costs of a particular control technology can be considered over an extended period of time into the future, rather than at the time of the rulemaking alone. Commenter believes the cost of CCS will not come down in the future because of a lack of demand for the technology, and that current costs should be used to assess the economic viability of CCS.
The EPA is assessing costs on both a per-plant and sector-side national basis and founds those costs to be reasonable, whether either of these metrics is considered alone, or together.
Fuel price volatility
Commenter 2470 states history has demonstrated that fuel costs can be volatile and the most cost-effective generating option can change over time. Further, commenter 8501 states the cost and system reliability implications of the proposed rule are understated and do not adequately take into consideration the swings in natural gas prices, the tendency for natural gas shortages, and the significant capital investments that must occur to deliver natural gas to new gas-fired power plants. There will be significant economic cost with the rule as a result of transition to greater reliance on natural gas as the fuel of choice for electricity generation.
Commenter 1419 states that they find industry economic arguments false. Industry argues against standards and limits citing costs for compliance.
The Regulatory Impact Analysis for the rule includes several illustrative analyses, including examining the costs of the rule under a range of natural gas prices. (See Chapter 5 of the RIA.) It is only when levelized natural gas prices increase significantly, to levels above those seen in EIA data going back to 1996 that there would be costs associated with the rule. Even in those cases, the health and climate benefits associated outweigh the costs except when examining unprecedented natural gas prices.  See also RIA chapter 4.5.4 indicating that new non-compliant coal capacity would not be price competitive with natural gas, even assuming natural gas price increases to historic highs. In all of the scenarios examined from AEO 2014, an NGCC unit remains more economical than a non-compliant coal unit, even in the scenarios that are most favorable to the construction of new coal (i.e., higher than projected natural gas prices and lower than projected coal prices.)
Allow supercritical boilers without CCS
Commenter 10870 states it appears the impetus for establishing the New Source Performance Standard (NSPS) under Section 111(b) of the CAA is for EPA to establish a legal pretext for EPA to seek to regulate existing EGUs under CAA Section 111(d), and if EPA's objective is to achieve Section 111(d) regulatory authority over existing EGUs, this can be accomplished without requiring CCS for new facilities, explaining that EPA could set a CO2 standard based on the most efficient super critical boilers without CCS. Commenter adds under CAA Section 111(b)(l)(B), EPA would have the opportunity to review in eight years whether it is necessary to revise the CO2 standard that is based on the most efficient super critical boilers. Commenter 10095 states a 2013 EPRI study compared the results of 12 scenarios that incorporated EPA's proposed standards to a baseline that allowed new coal-fired plants to be constructed without CCS, and EPRI's scenarios evaluated various natural gas price paths, the availability of new nuclear and new inter-regional transmission, and the lifetime of the existing coal fleet. Commenter continues that additional costs are incurred by the electricity sector in all scenarios due to the proposed standards. EPRI found the costs range from $15 billion to $293 billion through 2050 (net present value in 2010), and as required by Executive Order 12866 (1993), EPA must assess these costs and determine that the benefits of the proposal, if any, justify the costs.
Commenter 10618 states there is also an unfair bias against new supercritical coal within the LCOE calculations based on the assumed operation and maintenance costs. The values used by EPA from NETL for FOM and VOM of $70.6/kW-yr and $7.70/MWh (2011$) respectively are significantly higher than the $31.18/kW-yr and $4.47/MWh (2012$) being used by EIA. This further skews the comparison of natural gas versus conventional coal.
Commenter 9194 states EPA has heavily tipped the scales to "environmental impact" and claims that a need to assure "meaningful reductions" in emissions is what prevents EPA from determining that super-critical pulverized coal (SCPC) and Integrated Gasification Combined Cycle (IGCC) coal plants without CCS are BSER. Section 111 of the CAA does not address achievement of ambient air standards and is not a section of the CAA assigned specific emissions reduction goals. EPA's over-weighting of emissions reductions is absolutely critical to its designation of coal with CCS as BSER. Further, EPA provides no analysis of the non-air quality environmental impact of the proposed rule on non-EOR sequestration, and no analysis of the energy penalties that occur with CCS.
Commenter 9194 continues EPA should have compared the SCPC emissions to the typical CO2 emissions rate of existing coal-fired generating units. The CO2 emission rates of a new SCPC unit are significantly lower than the typical existing coal-fired EGU and would meet EPA's desire for significant CO2 emission reductions as shown by the table below.
Commenter 9775 states that the Bonanza solid-fuel waste fired project proposed in Uintah County, Utah is designed and permitted to utilize lower grade by-product of coal washing facilities and would be a relatively small circulating fluidized bed (CFB) unit. The proposed unit is permitted to a very low emission standard for NOx, SO2, and particulate matter, in many respects comparable to a gas fired unit, but the capital cost structure of such a CFB u n it is lower than a large, supercritical pulverized coal unit. The more economical cost of such a "niche project" compares competitively to gas fired alternatives, especially with added environmental and community benefits of disposing landfilled coal fines. The proposed standard, if it is applicable to all future units, effectively eliminates the ability to realize co-benefits of these diversified project opportunities. Low, stable energy prices and reliable power are key drivers for Utah's economy, and coal provides a significant amount of Utah's base load electricity.
In response to commenter 9775, the Deseret source is not a new source under the final standard of performance.  In response to comments urging selection of SCPC as BSER, see preamble Sections V.P.1 and V.K. (documenting the delta in CO2 emissions between an SCPC plant and a plant emitting at the level of the standard of performance). Further, as noted in other comment responses, the final standard of performance considers all the decision factors of section 111 (a), and does not assume a priori that emission reductions obviate consideration of other statutory factors.
New coal-fired power plants using higher efficiency technologies are competitive with natural gas combined cycle power
Commenter 9201 states that new coal-fired power plants using higher efficiency technologies are competitive with natural gas combined cycle power. They state that modest adjustments to EPA's input assumptions in the Reference Case conditions show conditions under which SCPC and NGCC are equivalent in terms of LCOE, and these modest changes erode the cost advantage of NGCC over SCPC found in EPA's assessment. Commenter challenges EPA's assumptions are unfounded and incorrect, and point to a lack of a robust and economically sound assessment of the ability of varying generation sources to compete.
Commenter 7976 states the lower combined cycle heat rates also mean that the combined cycle plants are much more competitive on the California power grids than for peakers. This results in the dispatch of combined cycle plants at a much high capacity factor than for peakers. Table A-3 (below) confirms that reasoning. California's modern combined cycle fleet generated 10 to 20 times as much energy as California's peaker fleet with only a 50% advantage in heat rate. Commenter adds that this data strongly implies the economic superiority of combined cycle because the much higher energy sales associated with higher capacity factors can support higher capital costs per installed KW. Combined cycle plants sometimes require a capital investment per installed KW that may exceed peaker plant investment by as much as a third, depending upon the project specific technologies and variations in regulation, land costs, labor costs, etc. Commenter offers the example of a project's capital cost alternatives, an excerpt from the Alternatives Analysis prepared by Brazos Electric Cooperative Inc. (Texas) in 2007, with the consulting assistance of Black & Veatch.
Commenter 7976 continues that Table 1 in California Energy Commission's Wholesale Cost of Electricity, 2009 Report projects that the energy cost rate of electricity from a combined cycle plant (in California) is a fraction of the cost from simple cycle plants. That's because the higher capital cost rate of combined cycle plants is amortized over a much higher level of energy production than simple cycle, which makes the $/MWh cost rate much lower for combined cycle. Commenter states that a reasonable conclusion is that the energy produced by combined cycle generation is generally much more economical (in terms of $/MWh of energy generated) than simple cycle peaker generation, even though the capital cost rate of combined cycle plants may be higher than the capital cost rate of simple cycle peaking plants.
Further, Commenter 10928 remarks that by effectively banning new higher efficiency coal power plants, EPA denies the nation the opportunity to maintain a diverse electric generation supply to fleet future load growth and replace the aging base load power fleet.
Commenter 10870 states the Proposed Rule will not result in fuel diversity and divests states like North Dakota with the primary authority to determine what sources should be in a state's energy generation portfolio. Commenter continues it is within the State of North Dakota's discretion to determine how best North Dakota's significant electricity demand can be met. North Dakota has an abundant supply of lignite coal that can be used to meet the future projected electricity demands. New efficient lignite-fueled baseload electric generation facilities should not be prohibited by the Proposed Rule for being an option available for meeting this substantial projected demand.
Commenter 10667 states Texas is the 5th largest coal-producing state in the U.S. Texas has about 23 billion tons of lignite deposits, with about 10 billion tons economically recoverable in today's market. There is enough economically recoverable lignite remaining to sustain Texas' current consumption for the next 100 years (these reserves far surpass oil and natural gas together in terms of in-state Btu equivalent energy reserves). This rate of consumption is significantly at risk, particularly if EPA finalizes a rule requiring the installation of CCS technology.
Commenter 11134 requests EPA reconsider regulations on new coal plants. The proposed rule will have an ultimate "trickle down" effect on many other parts of the industry. For example, commenter is a coal terminal located south of New Orleans, their terminal would certain feel the effects if domestic production fell, as well as their contractors and vendors that depend on us for jobs. Before making any drastic decisions, please think about the consequences on competition (price of energy), economy, and unemployment.  Commenter requests thinking about improving rather than removing coal from the energy mix and look at new an affordable technologies to keep our environment clean.
EPA is not precluding the construction of new coal-fired generation, and the rule includes the flexibility to promote construction of new coal capacity with technology to meet the requirements.  For example, there are multiple compliance pathways to meet the final standard of performance, including compliance options that are not dependent upon use of CCS. In addition, EPA's modeling, conducted using the Integrated Planning Model (IPM), as well as modeling conducted by the U.S. Energy Information Administration (EIA) showed that new generating capacity built through the period of analysis would be in compliance with the standard even in the baseline scenario and, as a result, the rule would not lead to changes in behavior. This finding held true even under a number of alternative scenarios. As a result, the EPA projected there would be negligible costs, benefits, energy impacts (including changes to electricity prices), employment impacts, or economic impacts associated with the rule in the period of analysis. (See Chapter 4 of the RIA.)

Regarding the comments by Commenters 10870 and 10667 that express concern about fuel diversity in North Dakota and Texas respectively, as producers of lignite. There is nothing in the final standards that precludes the use of lignite or prevents construction of new lignite-fired EGUs in those states. In fact the EPA specifically examines the achievability of the finals standards of performance over a range of operating conditions including startups, shutdowns, malfunctions, and the use of a variety of fuels, including the low rank subbituminous coal and lignite. See section V.J in the preamble and the in a Technical Support Document (TSD)  -  "Achievability of the Standard for Newly Constructed Steam Generating EGUs" available in the rulemaking docket.
Call for Flexibility and cost minimization analysis of standard
Commenter 10034 states that EPA should commit to working with EGU operators to gauge whether its standard does in fact provide operational flexibility and minimize costs.
Commenter 9772 recommends that EPA study the potential impact to our country's future energy security that would result from reducing the diversity of available future power sources. Commenter also recommends EPA move away from its regulatory approach to eliminate coal from America's energy portfolio and instead look for ways to incentivize transitional improvements such as construction of more efficient power plants and cost-effective carbon capture and sequestration technologies.
The final standard of performance for fossil-fuel fired EGUs can be achieved in a number of ways, and is not constrained geographically.
Need cumulative costs impact of regulated sources
Commenter 3176 states they are not aware of any meaningful analysis undertaken by the EPA as to the cumulative cost impacts resulting from implementation of, and compliance with, the suite of pending and issued rules affecting electric utility generating units. Considering the proposed carbon restrictions will address new and existing units, the need for a cumulative analysis is particularly justified. Commenter adds that it is important for the consuming public to be advised of the potential rate impacts associated with implementing the full suite of the EPA's recently proposed and newly issued regulations.

Commenter 9396 states that not examining the cumulative impact of its regulations means neither the price nor supply impacts of its rules have been adequate evaluated and the correct types of analyses needed to understand the impact on adequate supplies have not been conducted.  These estimated supply, price and reliability impacts from previous rulemakings do not include layering additional uncertainty and risk onto the electricity generation from EPAs proposed NSPS for CO2 which will have the practical effect of eliminating the development of new coal based generation. At a time when utilities need to plan and execute hundreds of millions of dollars of investments in existing units to comply with the CSAPR and MATS rules, EPA's decision to issue this proposed rule only adds greater uncertainty to the investment decision making process.

Commenter 10618 states  EPA's economic modeling used in this rulemaking has not appropriately assessed the impacts of the final MATS rule and other pending regulations, which will lead to the retirement of many coal-fired generating units, further increasing the demand and hence the price for natural gas. The associated reduction in coal use will also influence coal pricing (and reduce coal prices), making new coal fired generation more viable economically. Notably, when spreads between gas and coal prices reach approximately $4 per MMBtu, coal plants become economic to build relative to combined cycle gas plants.

Commenter 10082 states EPA should develop the rule for the electric power sector taking into account the cumulative impact of those rules on the various generation options.
EPA's modeling, conducted using the Integrated Planning Model (IPM), as well as modeling conducted by the U.S. Energy Information Administration (EIA) showed that new generating capacity built through the period of analysis would be in compliance with the standard even in the baseline scenario and, as a result, the rule would not lead to changes in behavior. This finding held true even under a number of alternative scenarios. As a result, the EPA projected there would be negligible costs, benefits, energy impacts (including changes to electricity prices), employment impacts, or economic impacts associated with the rule in the period of analysis. (See Chapter 4 of the RIA.) The baseline for this analysis included existing regulations, so this conclusion takes into account impacts of those actions.
Fuel diversity includes coal
Commenter 9034 states if coal were eliminated as a fuel source, then the grid will no longer have a reliable and affordable fuel source to fall back on when there are localized shortages of natural gas. Commenter adds the United States must have an "all of the above" energy policy.
Commenter 3093 strongly supports a portfolio strategy for domestic energy development. We believe a broad energy portfolio allows for the kind of economic growth and innovation that is key to sustainable prosperity for the entire country.
Commenter 9596 states EPA should regulate CO2 emissions in a manner that does not foreclose future fuel-use options, explaining that it would be unwise for the federal government to develop environmental regulations that pick winners and losers in energy markets. Rather, the best long-term strategy for ensuring stability in U.S. energy markets is to allow all sources of energy to compete on a level playing field. For these reasons, commenter believes EPA should adopt an NSPS that keeps coal as a fuel option if it makes good economic and business sense to build new highly efficient, well-controlled, coal-fueled generation in the future.
See preamble Section V.I.4.
Call for parametric sensitivity analysis
Commenter 9666 states the RIA did not conduct a parametric sensitivity [analysis] as presented in this paper but rather, addressed individual (and not cumulative) changes in capital cost and fuel price that moved in the same direction. In summary, the inputs assumed for Figure 5 represent one set of realistic conditions under which NGCC and SCPC are equivalent in terms of levelized cost of electricity.  The commenter provided discussion of EPA's sensitivity analysis.
The commenter is correct that EPA did not conduct a parametric sensitivity analysis as part of this rule. The RIA for the proposed and final rules relied upon sector-wide analysis conducted using the Integrated Planning Model (IPM), as well as modeling conducted by the U.S. Energy Information Administration (EIA). Both of these analyses showed that new generating capacity built through the period of analysis would be in compliance with the standard in the baseline scenario, and as a result, there would be no change in behavior as a result of the standard. In addition, the analysis considered a number of alternative scenarios developed by EIA. This finding held true even under the alternative scenarios that would be most likely to result in new coal-fired capacity. As a result, the EPA projected there would be negligible costs, benefits, or energy impacts (including changes to natural gas prices) associated with the rule in the period of analysis. See RIA Chapter 4.

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

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

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

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

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

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

Commenter 9600 states the contention that based on these early projects the next-of-a-kind coal-based EGUs with partial carbon capture will somehow even approximate the LCOE data in Table 6 is not only arbitrary but totally meritless. Even assuming that actual experimental cost data were not available, the DOE reports upon which EPA relies were not peer reviewed and underlying assumptions were not made available for comment in connection with this rulemaking.

Commenter 9407 states the contention that based on these early projects the next-of-a-kind coal-based EGUs with partial carbon capture will somehow even approximate the LCOE data in Table 6 is arbitrary  and without merit.

Commenter 9407 states the contention that based on these early projects the next-of-a-kind coal-based EGUs with partial carbon capture will somehow even approximate the LCOE data in Table 6 is arbitrary  and without merit.
Most of these comments are addressed in the preamble and in RTC 6, and the Cichanowicz appendix to UARG comments is addressed at response 3.3-16a above.  See section V.7. (costs decrease over time) and V.I.2. (reasonableness of NETL cost projections). Commenter 10046 suggests that DOE/NETL does not believe next plant costs will be NOAK.  The cost estimates for the final rule reflect the latest NETL cost study based on vendor quotes for the Shell Cansolv process  -  the process in current use at the Boundary Dam facility.  NETL believes these costs to be reliable as does EPA.  The costs also accord with prices quoted in the marketplace currently (see preamble section V.I.2.c) and cost estimates in other studies.  Id. section V.I.2.b. Commenters 10046 and 8971 claim that plants not yet built cannot provide enough information for next plants to be next-of-a-kind.  This is a dubious proposition, given that on-going experience provides useful information informing subsequent plants.  But there are operating plants  -  Boundary Dam is operational, the CCS portion of the Boundary Dam project came in at budget (the cost overruns commenters cite were for the SCPC), and the developer projects substantial reductions in cost for the next plant to be built.

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