1 TABLE OF CONTENTS

3.5 Alternative RE Approach

................................ ................................ ................................ ....... 2 3.5.1 Alternative RE approach methodology

................................ ................................ ............. 2 3.5.2 RE target generation methodology by technology type

................................ .................. 52 3.5.3 Potential alternative method using technical and e conomic potential

.......................... 62 3.5.4 State

- level results

................................ ................................ ................................ ............... 71 3.5.5 Regionalized approach

................................ ................................ ................................ ...... 81 3.5.6 Other

................................ ................................ ................................ ................................ . 100 3.6 Interaction of Building Blocks

................................ ................................ ........................... 105 3.7 Fuel Switching

................................ ................................ ................................ ..................... 158 3.7.1 Coal

- to

- natural gas

................................ ................................ ................................ .......... 158 3.7.2 Biomass co

- firing

................................ ................................ ................................ .............. 170 3.7.3 Other

................................ ................................ ................................ ................................ . 173 3.8 Carbon Capture & Storage

................................ ................................ ................................ 175 3.8.1 Post

- combustion capture

................................ ................................ ................................ . 175 3.8.2 Geologic storage

................................ ................................ ................................ ............... 190 3.8.3 Enhanced oil recovery (EOR)

................................ ................................ ......................... 194 3.8.4 Retrofit CCS: technical feasibility

................................ ................................ .................. 201 3.8.5 Retrofit CCS: reasonableness of cost

................................ ................................ ............. 212 3.8.6 Retrofit CCS: emission reductions and promotion of advanced technology

............. 221 3.8.7 Other

................................ ................................ ................................ ................................ . 229 3.9 New NGCC capacity

................................ ................................ ................................ ........... 241 3.10 H eat Rate reduction opportunities for non

- coal fossil fuel

- fired EGUs

...................... 287 3.11 Potential emission reduction measures not used to s et proposed goals

....................... 315 3.12 Other

................................ ................................ ................................ ................................ .. 4022 3.5 ALTERNATIVE RE A PPROACH

This section addresses comments on the EPA’s alternative RE approach, including methodologies, state

- level results, and regionalized approach. We have organized the comments in this section under six subsections, 3. 5 .1 to 3. 5 .6

. Responses to the comment topics of these subsections are discussed below along with summaries of the specific public comments.

3.5.1 Alternative RE approach methodology

This section addresses comments on the specific methodology for the alternative RE approach.

Commenters have raised a number of issues related to this subsection which are organized by topics (comments) below. Responses are provided for these topics.

Com ment 1: Commenters stated that EPA's Alternative RE Approach is a more appropriate measure of achievable and cost

- effective renewable energy than the Proposed RE Approach

. Response 1: The resources, data, and information provided in these comments were val uable in finalizing the building block 3 methodology

. The EPA is finalizing an incremental building block 3 target generation level based on historical patterns of deployment for each of the BSER RE technologies (utility

- scale solar PV, CSP, onshore wind, geothermal, and hydropower) coupled with expectations of future capacity factors

. The technical feasibility and cost

effectiveness of these target generation levels are validated in IPM through a methodology based on the Alternative RE approach

. Based on c ommenters feedback, the primary changes to the Alternative RE approach include removal of the technical potential limiter and updated cost and performance assumptions f or the onshore wind and solar technologies

. The final building block 3 methodology is de scribed in section V.E of the preamble and in the GHG Mitigation Measures TSD

. The following are summaries of the specific public comments under this comment:

Commenters stated that EPA's Alternative RE Approach is a more appropriate measure of achievable and cost

- effective renewable energy than the Proposed RE Approach which relies on historical state policies.

Commenter s noted that rather than evaluating the capacity of each state's electric system to develop and integrate renewable energy over time, the Proposed Rule outlines an approach that quantifies achievable generation from renewable energy by pointing to regional "best practices" embodied by state rene wable portfolio standard (RPS) policies as a proxy for what is technically feasible, demonstrated, and cost

- effective

. Commenters this is a conceptually different approach than an independent finding of the technically feasible, cost

- effective, and adequat ely demonstrated level of emission reduction, as EPA conducted for Building Blocks 1 and 2 and the nuclear energy component of Building Block 3. Commenters suggested that EPA should instead adopt the Alternative RE Approach, which is based on a conceptual framework more similar to EPA's approach to the other Building Blocks. Commenters stated that generation from various3 forms of renewable energy can effectively displace CO2 emissions from affected EGUs, and while EPA is right to include renewable energy ge neration as part of its evaluation and application of BSER, the particular approach that EPA has chosen significantly underestimates the quantity of MWh that can be generated by renewables in each state over the 2020

- 2030 compliance period. Therefore, whil e commenters supported EPA's inclusion of renewable energy into BSER as part of Building Block 3, they propose a number of revisions to EPA's methodology to better capture the achievable, cost

- effective, and adequately demonstrated growth of renewable ener gy.

Commenters stated that the Alternative RE Approach would be far more appropriate than the rough RPS

- based approach which commenters felt is particularly problematic for the Southeast region, including Mississippi

. Commenters believed that EPA made no s howing that the states in the Southeast region, North Carolina in particular, have renewable generation comparable to that of Mississippi. Commenters believed that EPA's Proposed Approach failed to analyze any differences in permitting, transmission access , and project financing that might affect renewable potential in different states and urged EPA to establish targets based on reasonable, cost

effective, wind potential as Mississippi has not been identified as a prime area to develop wind

resources. Comme nters stated that EPA's assumptions should be grounded on accurate assessments of technological and economic potential by state, and they should also account for relative potential, particularly in the context of very short lead times before the compliance period begins. Commenters noted that it makes little sense for Mississippi to be competing intensively over the next five years for capital, equipment, and construction resources with other states that are much better suited to generating electricity from wind and solar.

Commenters believed that the Alternative RE Approach is more accurate because the approach does not rely on one policy to determine the solar potential in a state, as the RPS approach does, thus the Alternative RE Approach would set a more realistic expectation of the amount of solar growth feasible that will create a balanced energy portfolio in each state. Commenters noted that the NRDC engaged with ICF to run the IPM to reproduce EPA's RE Market Potential run based on the below solar ene rgy recommendations, using up

- to

- date cost and performance assumptions for renewable energy technologies. Commenters noted that the resulting national target for renewable generation nearly doubles from EPA's approaches, growing from 520

- 530 TWh to ~930 TW h which clearly demonstrates that significantly higher levels of renewable energy are both technically and economically achievable, compared to the levels proposed in either of EPA's target

- setting approaches.

Commenters believed the A lternative RE A pproa ch to be preferable because it would establish targets for each state based not upon RPS policies that happen to have been adopted in neighboring states, but upon an evaluation by National Renewable Energy Laboratory ('NREL') of resource availability in ea ch state. Commenters noted, however, that EPA's A lternative RE A pproach would cap each state's renewable generation target at a level determined pursuant to EPA's Integrated Planning Model ('IPM'), even if that level is substantially lower than the level d etermined by NREL to be achievable. Commenters stated that because the IPM

- based cap depends largely upon the percentage of total generation potential achieved by 2012 for each type of renewable resource, in its current form it fails to take into account t he likelihood that the cost of renewable technologies will continue to fall and that the deployment of these technologies will continue to accelerate. Commenters recommended that EPA adopt the A lternative RE A pproach,4 but incorporate into the IPM more rece nt data evidencing continued acceleration of the deployment of these technologies. Commenters also u rged EPA to modify the Al ternative RE A pproach to include both offshore wind and distributed solar photovoltaic generation, both of which are clearly 'adequately demonstrated' within the meaning of Section 111(d).

Commenters stated that the Alternative RE Approach is preferred by the Nevada Agencies as its analysis and resulting targets are attainable and represent a more reasonable assessment of RE pot ential in Nevada. Commenters noted that the proposed rule presents target values for state

- by

RE generation calculated for the final level (2029) and interim level (2 024) for both the proposed and A lternative RE A pproach, but noted that the A lternative RE A pproach values differ for Nevada as presented in tables in the GHG Abatement Measures TSO and the Alternative RE Approach TSO. Commenters stated that it is unclear which alternative scenario target values are correct for the case excluding existing hydrop ower.

Commenters stated that while they favor the Alternative RE Approach over the Proposed RE Approach, EPA should use caution when calculating BSER according to historic RE resource growth and technical potential, as past RE growth is not always an appro priate gauge for future RE growth, and actual RE generation is not a direct corollary of technical potential. Additionally,

c ommenters asked EPA to consider adding an indicator of the cost of intermittent resources in addition to the avoided cost metric th at is calculated by IPM model runs because as RE adoption levels increase, associated RE transmission and storage concerns and costs should also be considered.

Commenters noted that the Alternative RE Approach allows scientific experts to study all the pot ential renewable electricity resources a state possesses and place these on a level playing field with each other which c ommenters agree with, as one of their primary goals is to ensure all forms of renewable energy are treated equally as compared to each other. Commenters supported the Alternative RE Approach and noted that the Proposed RE Approach relies on RPSs' which

are crafted through a political process and as such are not immune to political pressures and pitfalls of picking winners and losers and a re slow to adopt technologies that have significant renewable electricity potential but little political support.

Commenters stated they are strongly in favor of the Alternative RE Approach in comparison to the proposed RE scenario. Commenters stated the m e thodology incorporated for the A lternative RE A pproach is much more in

- line with least

- cost planning principles utilized by utility system planners across the nation. Commenters stated that considering regional resource potentials for each renewable resou rce, along with the associated market driven cost parameters, is fundamentally a more solid and prudent approach. Commenters noted that although the A lternative RE A pproach is favorable in terms of methodology construct, there are still other concerns with this approach.

Commenters agreed with EPA's Alternative RE Approach, but disagreed with some of the methodology and data utilized by EPA in its calculations within the approach. Commenters stated that it appears that EPA has materially underestimated the contribution that RE can make toward reducing emissions in performing its calculations under the Alternative RE Approach. Commenters noted, specifically, that EPA underestimates the contribution available from RE due to the use of technical potential (inap propriate benchmark development rate that artificially limits5 the contribution of RE, outdated inputs regarding RE resource availability and current RE generation) and market potential (outdated inputs regarding the costs and performance of RE technology, exclusion of distributed RE generation potential).

Commenters supported the Alternative RE Approach, but believed that the analysis that EPA relies on significantly underestimates the actual potential for renewable energy by failing to reflect what current technologies can deliver at very reasonable cost. C ommenters urged EPA to conduct a technical and economic analysis of potential using current cost and production data and correcting errors in EPA's original analysis.

Commenters supported the Alternative RE Approach to the extent that EPA believes it is necessary to set a specific numerical renewable target in the final rule. Commenters requested that EPA allow the states the option of recalculating the renewable component of the state target using a stat e

- by

- state approach, including the adoption of EPA's alternative RE target if deemed reasonable/applicable. Commenters added that if EPA should move to a biomass accounting framework, they request that the Agency recalculate the state renewable component of the target calculation and adjust the state targets accordingly.

Commenters questioned the feasibility of the extent of renewable development assumed in the proposed rule because resources and market condition differences among states are not taken into account. Commenters stated EPA's approach dilutes these differences by aggrega ting states into regions and applying regional growth factors and regional RE targets, without specifying criteria for those growth factors or targets. Commenters stated that EPA's assumption that the state regional portfolio standards used to calculate th e regional RE target are consistent among states in terms of the types of activities allowed to meet those standards is inherently flawed. Commenters stated given these flawed assumptions, they recommended that EPA use the A lternat iv e RE A pproach proposed in this rulemaking to quantify renewable generation, excluding hydroelectric generation, that focuses on the technical and market potential within each state.

Commenters agreed that EPA's Alternative RE Approach provided a meaningful compliance obligation under the rule for Iowa, but offered the following recommendations to the approach: EPA should individualize the development rate for leading states and no state's development rate should be capped by an averaging of other states that are not similarly sit uated; EPA should use the technical potential as more than a starting point that can be later eliminated; EPA should increase the generation levels for states with very high levels of technical potential and very high levels of renewable energy installatio ns; EPA should provide clear step

- by

- step calculations for Building Block 3 generation levels for all states.

Commenters recommended that in states where the existing renewables rate exceeds the NREL projection, the renewables potential be set at the exist ing rate plus a reasonable growth factor. Commenters noted that the generation figures from this NREL report may not be a viable approach for some states given that it calculates renewable potential as above a state's current generation needs and suggested that EPA could resolve this issue by capping the amount of non

hydro renewables that could be feasible at 25 percent of a state's generation fleet, a level surpassed in many European countries, and adjusted to allow for a reasonable growth rate of the

res ources in any given state.6 Commenters urged EPA to should review and utilize for the purposes BSER calculations the most up

- to

- date literature for projections on costs, technological, economic and market potential for renewable energy and adjust projectio ns on the potential for these resources to achieve emission reductions accordingly.

Commenters noted that multi

- state compliance plans are at the discretion of the states; therefore, EPA cannot set targets assuming that multi

- state coordination will occur and therefore the only approach afforded under Section 111(d) must be based on a state

- specific, in

- state feasibility analysis.

Commenters preferred EPA's alternative proposed approach but stated that EPA must provide a reasonable basis for any RE growth r ate and for any assumptions about future decreases in the costs of RE technologies.

Commenters stated that there is a demonstrated basis for strengthening state

- specific targets for some states, and that the factors identified in EPA's NODA merit careful c onsideration by the EPA.

Commenters stated that these alternative RE targets are more closely aligned with existing RPS goals when ACPs are factor ed in as a compliance tool, and noted that they are committed to the existing state RPS requirements that are fully functioning in the Northeast States. Commenters stated that they do not support any efforts to use the CPP state renewable analysis to redefine RPS requirements, or that would affect the existing generation unit qualification requirements for each st ate's renewable requirements.

Commenters stated that if NREL publishes a new study assessing the technical potential of different RE types, as is anticipated, EPA should base its approach on the updated data reflected by this study.

Comment 2: Commenters stated that EPA's Alternative RE Approach is based on a more technically accurate model but noted that the approach is problematic in that it calculates renewable energy development within a state as a percentage of in

- state electricity generation rather t han in

- state electricity consumption.

Response 2: The EPA has instituted a modeling constraint at each of the 64 U.S. IPM regions that limits generation from intermittent RE resources (wind and solar) to 30 percent of net energy for load

. Additionally, the final building block 3 methodology does not rely on state

- specific deployment estimates, but rather cost

- effective RE at an interconnection level

. The EPA addresses considerations related to the technical feasibility and availability of regional RE

resour ces in both the preamble (section V.E) and GHG Mitigation Measures TSD.

The following are summaries of the specific public comments under this comment:

Commenters stated that EPA's Alternative RE Approach sets a more aggressive path for states and is based on a more technically accurate model that takes into account the state's potential renewable energy resources and also the economic and technical constraints of the transmission7 system but noted that the approach is problematic in that it calculates renew able energy development within a state as a percentage of in

- state electricity generation rather than in

- state electricity consumption. Commenters noted that this does not correlate well with existing state actions as most existing RPSs implement a renewab le energy mandate as a percentage of consumption. Commenters noted, for example, that New Mexico would have a final renewable standard of about 53 percent of total projected state electricity consumption in 2030 when considering the state's low consumption and high technical potential. Commenters questioned whether this level of non

- hydropower renewable resource integration is adequately demonstrated and can constitute BSER since no place in the world has yet to consistently achieve a 53 percent renewable e nergy level without heavy reliance on hydropower. Commenters believed that it is unlikely that a state would undertake a legal obligation to build the necessary regional transmission for export and the legal obligation to successfully market renewable ener gy to out

of

- state buyers, as state governments do not typically engage in such activities. Commenters stated that this anomaly can be corrected by implementing a final step in the alternative methodology that would cap the state annual renewable energy st andards at 30 percent of the compliance year's projected domestic consumption. Commenters stated that this level corresponds approximately to the "best practice" level which California will achieve by 2020, which Colorado's investor

- owned utilities will al so achieve on their systems by 2020, and which certain countries in the European Union have achieved or will achieve by 2020.

Comment 3: Commenters expressed concerns regarding how the EPA accounts for ownership of compliance values from RE projects under the Alternative RE Approach.

Response 3: The final building block 3 methodology does not rely on state

- specific deployment estimates, but rather cost

- effective RE at an interconnection level

. Further, building block 3 target generation level is incremental to 2012, which eliminates many of the issues associated with establishing and crediting ‘baseline’ RE generation

. For the EPA’s response to this comment, see section s V.A. and V.E of the Final Rule preamble of the CPP and chapter 4 of the GHG M itigation Measures TSD for CPP Final Rule

. The following are summaries of the specific public comments under this comment:

Commenters recommended to adopt EPA's Alternative RE approach. Commenters stated that given the deficiencies in the proposed approac h , they believe the A lternative RE A pproach would be an improvement. Commenters stated, the A lternative RE A pproach, however, does not resolve the issue of ownership of the compliance value from renewable projects located in one state but currently meeting another state's RPS obligation. If the final rule adopts the Alternative RE Approach, the c ommenters suggested EPA should likewise issue clear guidance that any such renewables included in a state's baseline and goal calculation shall be available to that state for compliance purposes.

Commenters stated that EPA's renewable approach must recognize that individual state RES programs allow the use of out

- of

- state state renewable energy credits (RECs) for compliance. Commenters noted that these mechanisms ena ble regulated utilities to meet RES mandates cost

effectively by building or purchasing renewable resources in the most optimal location.8 Commenters recommended that the off

- taker of power should have the final say on where the credit should reside for com pliance accounting purposes.

Comment 4: Commenters stated that if EPA decides to use a method in which the resource potential calculation is based to some extent on existing renewable energy generation, EPA should allocate existing renewable generation to states by looking at power purchase agreements for that generation, not the geographic location of the renewable generation. Commenters stated that this change would better reflect where and how existing renewable energy is being used.

Response 4: The fin al building block 3 methodology does not rely on state

- specific deployment estimates, but rather cost

- effective RE at an interconnection level

. Further, building block 3 target generation level is incremental to 2012

. The final methodology is described in section V.E of the preamble.

Comment 5: Commenters opposed the EPA's alternative approach, as they believed that it failed to appropriately account for cost

- effective renewables generation. See section V.E.6 of preamble to CPP Final Rule.

Response 5: The basis for building block 3 generation levels is historical RE capacity deployment, not modeled economic potential

. Refer to section V.E of the final rule preamble of the CPP and chapter 4 of the GHG Mitigation Measures TSD for CPP Final Rule for additiona l detail regarding how EPA defines cost

- effective renewable generation under building block 3

. Building block 3 is not applied to Alaska, Hawaii, or the U.S. territories

. Affected EGUs in Areas of Indian Country are subjected to the same interconnection

- ba sed building block 3 as other affected EGUs.

The following are summaries of the specific public comments under this comment:

Commenters opposed EPA's alternative less stringent approach, as they believed that it failed to appropriately account for cost

- eff ective renewables generation to an even greater degree than the proposed approach. Commenters noted that in the U.S. territories of Guam and Puerto Rico, for example, renewables have shown such promise that the areas have created renewable energy goals, re spectively. Commenters also noted a DOE Office of Indian Energy and NREL study which found that although American Indian land comprises just 2 percent of total U.S. land, it contains an estimated 5 percent of national renewable energy resources.

Comment 6: Commenters opposed EPA's proposed Alternative RE Approach because potential alone is too slender a foundation for a state goal.

Response 6: The resources and data provided in this comment were valuable in finalizing the building block 3 methodology

. The basis for building block 3 target generation levels is the observed pattern of historical development for each of the BSER RE technologies

. Modeling9 projections remain an important aspect of the overall methodology in validating the technical feasibili ty and cost

- effectiveness of the target generation level

. The EPA has adopted a number of the proposed changes suggested by the commenter s , including removal of the technical potential limiter and using current cost and performance estimates from NREL for onshore wind and solar technologies . The final methodology is described in section V.E of the preamble and in the GHG Mitigation Measures TSD

. The following are summaries of the specific public comments under this comment:

Commenters opposed EPA's propose d Alternative RE Approach because potential alone is too slender a foundation for a state goal.

Commenters stated that the A lternative RE A pproach underestimates the industry's potential and calculates only the impact of utility

- scale renewable energy ins tallations and does not consider distributed generation resources, which is very relevant in New York given the continuing rapid deployment of residential and commercial solar PV, with an estimated bounded technical potential of 54,000 GWh by 2030, as well as a growing market for behind

- the

- meter wind in New York's more rural areas. Commenters also noted that the A lternative RE A pproach

uses inaccurate and outdated assumptions about technology cost and performance; and bases 2030 targets on 2012 installatio ns, ignoring the way market adoption has accelerated due to declining costs. Commenters also disagreed with EPA's exclusion of offshore wind under the A lternative RE A pproach. Commenters urged EPA to use a modified version of the proposed alternative renew able energy approach for calculation of building block three which should better reflect an assessment of what levels of increased generation from renewable energy
are cost

- effectively achievable. Commenters echoed AWEA's re commended modifications to the A lternative RE A pproach which included: (1) removing the arbitrary cap on the percentage of technical renewable resources that can be developed in a state or region, (2) using current real

world data on the cost of renewable energy technologies, as costs ha ve declined rapidly in recent years for both wind and solar, (3) using DOE and NREL publications for projecting future costs and performance of renewable energy, (4) not using a firm cap on the percentage of variable wind and solar that can be deployed or use the results of integration studies (performed by NREL or ISOs) that generally have found that 40

- 50 percent integration is achievable, (5) integrating changes to the power system and mix of generation that will occur as a result of this Proposal, (6) i ncluding some projections for new transmission lines, however conservative, (7) allocating the projected estimated total regional renewable MWh to states based on the amount of total generation in each state, and (8) including load growth in modeling likel y renewable energy growth.

Comment 7 : Commenters noted that the Alternative RE A pproach results in RE goals for a number of states that are in excess of 40 percent (excluding existing hydropower) of the states' 2012 retail sales.

Response 7 : The final b uilding block 3 methodology does not rely on state

- specific deployment estimates, but rather cost

- effective RE at an interconnection level

. The EPA addresses considerations related to the technical feasibility and associated grid integration costs of10 signi ficant RE penetration in both the preamble (section V.E) and GHG Mitigation Measures TSD. The final methodology is described in section V.E of the preamble.

The following are summaries of the specific public comments under this comment:

Commenters noted that the Alternative RE Approach results in RE goals for a number of states that are in excess of 40 percent (excluding existing hydropower) of the states' 2012 retail sales. Commenters noted that in two states, Kansas and South Dakota, the RE goal e xceeds 100 percent (excluding existing hydro) of 2012 retail sales

-- a high level which has no precedent in actual electric system operations and therefore does not appear to be remotely feasible. Commenters stated that the excessively high levels of these RE goals clearly indicate the unworkability of the EPA A lternative RE A pproach for setting RE goals for states.

Commenters stated that they did not have sufficient time to fully analyze the proposal. Commenters stated that they were unable to provide any m eaningful comments on this part of the NODA at the time because EPA had provided no additional data or information. Commenters added, however, that based on their limited review of the NODA, they do not believe it resolves the many fundamental problems wit h Block 3 they had previously outlined.

Comment 8 : Commenters stated the alternative RE approach is unworkable, especially for a state which has already reached its regional RE generation target under EPA's proposed approach

. Response 8 : The final building block 3 methodology does not rely on state

- specific deployment estimates, but rather cost

- effective RE at an interconnection level

. The EPA addresses considerations related to the technical feasibility and associated grid integration costs of sign ificant RE penetration in both the preamble (section V.E) and GHG Mitigation Measures TSD.

The following are summaries of the specific public comments under this comment:

Commenters stated the Alternative Renewable Energy approach is unworkable. Commenters at first glance, it appears to solve several issues with EPA's proposed approach that uses RPS

- based regional renewable energy targets, however, applying this Alternative RE Approach to EPA's calculation of state

- wide emission goals has a profound impact on the current proposed goals. Commenters stated this is particularly true for a state which has already reached its regional RE generation target under EPA's proposed approach.

Commenters provided the example of South Dakota, which is in the North Centra l region that has an average regional RE generation target of 15 percent under EPA's proposed approach. Commenters stated South Dakota has already reached its regional RE target, with 2,915 GWh of RE generation in 2012, and thus its obligation under the ta rget is capped at its share of the 15 percent regional RE target, 1,819 GWh of RE generation. Commenters stated that under the Alternative RE A pproach, South Dakota's obligation under the target is not capped, and instead, South Dakota's state

- level 2030 g eneration target, excluding existing hydropower, is 19,156 GWh of RE generation. Commenters stated this generation target would be incorporated into the11 denominator of the state goal calculation in place of the RE generation levels quantified using EPA's p roposed approach. Commenters including South Dakota's generation target based on the A lternative RE A pproach causes South Dakota's final rate

- based CO2 emission performance goal to decrease from 741 lbs CO2/MWh under EPA's proposed approach to 185 lbs CO2/MWh under the A lternative RE A pproach. Commenters stated this would dramatically and unsustainably in crease the cost curve for compliance. Commenters stated the percent decline in South Dakota's state emission rate, a state with one of the lowest CO2 emissions rates in the nation, that the Proposed Rule requires would increase from 35 percent to 84 pe rcen t if EPA were to adopt the A lternative RE A pproach for quantifying RE for BSER. Commenters stated this is an extremely expensive compliance alternative. Commenters provided a calculation of the EPA's state goal for South Dakota under the A lternative RE A pp roach.

Commenters referenced page 8 of the Alternative RE Approach TSD, that states would not be required to achieve the absolute levels of target gener ation quantified under the A lternative RE A pproach and incorporated into the denominator of the state go als. Commenters also stated EPA notes that states may consider including in their state plans compliance measures that do not rely heavily on expanding their RE capacity. Commenters stated that in practice, however, it is difficult to see how certain state s will meet their goals if EPA chooses the Alternative RE A pproach to be used as part of BSER. Commenters stated that the multitude of issues that surround the expansion of RE cannot be adequately taken into account by the use of the IPM, as relied upon by EPA, to project potential RE generation expansion and those affected by this A lternative RE A pproach cannot provide substantial comments on how they might be impacted because of that.

Commenters stated that the expansion of RE is highly dependent on avail able transmission, and any approach to quantify RE potential should take into account transmission constraints, engineering design constraints, such as hosting capacity, cost constraints, and the additional issues mentioned elsewhere in these comments, sur rounding new transmission construction that come from siting, permitting, environmental impacts, and landowner opposition. Commenters stated that for some states, the amount of renewable growth that EPA expects may well turn out to be unachievable, and Sta tes should not be forced to make up the difference elsewhere in their state plans for compliance.

Comment 9 : Commenters stated that an alternative that bases the projected RE growth rate on a state's existing RE development as of 2012 exhibits many flaws.

Response 9 : The final building block 3 methodology does not rely on state

- specific deployment estimates, but rather cos t

- effective RE at an interconnection level

. The EPA addresses considerations related to the technical feasibility and associated grid integration costs of significant RE penetration in both the preamble (section V.E) and GHG Mitigation Measures TSD.

The fo llowing are summaries of the specific public comments under this comment:12 Commenters stated that an alternative that bases the projected RE growth rate on a state's existing RE development as of 2012 exhibits many flaws. Commenters stated that existing dev elopment in 2012 may have taken years to accrue and may represent the lowest hanging fruit and further iterated that is not appropriate to assume that the quantity of development at any given point in time represents a reasonable annual growth rate.

Comme nters noted, for example, that Oklahoma wind development grew quickly over the past 5

- 7 years, and continued growth is assured; however, the near

- term growth rate may be slower due to an increase in legal, zoning, and transmission capacity issues. Commente rs further noted that

a quantity achieved in 5

- 7 years cannot be assumed to be repeated on an annual basis. Commenters concluded that since it is based only on potential and does not take into consideration cost and other real

- world effects, this alternati ve is too general to represent a realistic scenario for all states.

Comment 10 : Commenters stated that the alternative RE approach unfairly punishes several states that have already taken early action that have been leaders in developing RE.

Response 10 : The final building block 3 methodology does not rely on state

- specific deployment estimates or create state

- specific requirements , but rather establishes a level of cost

- effective RE at an interconnection level

. The EPA addresses considerations related to the technical feasibility and associated grid integration costs of significant RE penetration in both the preamble (section V.E) and GHG Mitigation Measures TSD.

The following are summaries of the specific public comments under this comment:

Commenters stated that the Alternative RE Approach would increase RE targets for many states that have already developed significant amounts of RE generation and therefore unfairly punishes several states that have already taken early action that have been leaders in developing RE.

Commenters noted, for example, that non

- hydro RE accounted for 18 percent of Minnesota's 2012 generation and under the proposed approach, by 2029 Minnesota's non

- hydro RE would be required to constitute 15 percent of the state's 2012 generation as opposed to 36 perce nt under the alternative. Commenters also noted that the alternative also exacerbates state performance goal disparities as it requires patently unreachable levels of RE generation in some states.

Commenters stated that if IPM results demonstrate that thes e states can continue to develop their renewable resources at a reasonable cost, then these states' targets should be set accordingly. Commenters added that cost

- effective renewable resources should not be arbitrarily excluded from the BSER determination b ased on artificial constraints such as the benchmark development rates described in the Alternative Proposal.

Comment 1 1 : Commenters stated that the Alternative RE Approach for calculating RE goals does not reflect BSER.13 Response 1 1 : For a detailed explan ation regarding the inclusion of incremental RE to the BSER refer to section V of the preamble. Specifically, t he final building block 3 methodology does not include the benchmark development rate that relied on NREL technical potential data

. More broadly, t he EPA addresses considerations related to the technical feasibility and associated grid integration costs of significant RE penetration in both the preamble (section V.E) and GHG Mitigation Measures TSD.

The following are summaries of the specific publi c comments under this comment:

Commenters stated that the Alternative RE Approach for calculating RE goals does not reflect BSER. Commenters stated that the Alternative RE Approach's lack of connection to how renewable energy could actually be used within any given state precludes its use as a "best system of emission reduction" that has been "adequately demonstrated". Commenters noted that the authors of the NREL paper that EPA relies on specifically acknowledge the limitations of their analysis. Commenters added that EPA acknowledged these shortcomings but believed that

Comment 1 2 : Commenters stated that EPA's methodology is flawed as it is based on unsubstantiated assump tions regarding the rate at which states can develop renewable resources and the future costs of those technologies.

Response 1 2 : The resources and data provided in this comment were valuable in finalizing the building block 3 methodology

. The basis for b uilding block 3 target generation levels is the observed pattern of historical development for each of the BSER RE technologies

. Modeling projections remain an important aspect of the overall methodology in validating the technical feasibility and cost

- eff ectiveness of the target generation level

. The EPA has adopted a number of the changes to the final methodology , including removal of the technical potential limiter and using current cost and performance estimates from NREL for onshore wind and utility

- scale solar PV. The final methodology is described in section V.E of the preamble and in the GHG Mitigation Measu res TSD

. The following are summaries of the specific public comments under this comment:

Commenters stated that EPA's methodology and the results of its analysis are fundamentally flawed in that they are premised on incomplete, unsubstantiated assumptions regarding the rate at which states can develop renewable resources and the future costs of those technologies.

Commenters stated that the use of one single GIS analysis should not be used to determine technical potential under this proposal and believed that EPA ignored individual state

- by

- state RE performance and, true technical potential, and costs of these measures

.

Comment 1 3 : Commenters stated that the alternative RE approach would increase the disparity of targets between states and would create significant winners and losers at the state level by parsing state

- based results from an integrated national model.14 Response 1 3 : The final building block 3 methodology does not rely on state

- specific deployment estimates, but rather cost

- effective RE at an interconnection level

. The stringency associated with building block 3 target generation levels for each interconnection is assigned to all of the affected sources within that interconnection

. Specific to these c ommenters concerns, this approach reduces the disparity between state goals

. The EPA addresses considerations related to the technical feasibility and associated grid integration costs of significant RE penetration in both the preamble (section V.E) and GHG Mitigation Measures TSD.

The following are summaries of the specific public comments under this comment:

Commenters stated that the Alternative RE Approach would increase the disparity of targets between states and would create significant winners in loser at the state level by parsing state

ba sed results from an integrated national model.

Commenters strongly opposed the Alternat iv e RE Approach and urged EPA to not adopt this approach into the final rule, as it would result in even more stringent emission rate goals in states that already have d eveloped significant amounts of renewable generation, like Oklahoma, because these states tend to be located in areas with renewable resources and the "potential

based" analysis employed by EPA has little connection to practically or economically developab le outcomes. Thus, c ommenters stated that the Alternat iv e RE Approach exacerbates state performance goal disparities. Commenters stated that it requires patently unreachable levels of renewable energy generation in some states. Commenters noted that the al ternative would require that by 2029 non

- hydro renewable energy would constitute 72 percent of New Mexico's 2012 generation and in contrast, the alternative prescribes renewable generation targets constituting 2 percent or less of 2012 generation in 13 sta tes.

Commenters noted that the emissions reductions targets already range from 11% to 72% from 2012 to 2030 under the rule as proposed, which they believed to be a major issue that creates unfairness between states and may stymie regional compliance cooperation. Commenter s stated that the Alternative RE Approach would exacerbate the issue by creating patently unfair and even unreachable levels of renewable generation in some states, such as New Mexico at 72% and South Dakota at 159%.

Commenters also stated that targets ex ceeding 100% between Kansas at 115% and South Dakota at 159% of 2012 generation by 2029 create unfairness between states. Commenters stated that if these numbers were applied to state emission rate goals, the CO2 emission rate goal for the states would be reduced and likely force out any fossil resources necessary to provide firm energy to support the projected level of renewable deployment. Commenters also stated that as this level of renewable energy would be in excess of in

- state needs, these states woul d be legally required to produce emissions reductions that could only be achieved by extreme penetration of renewable energy without any requirement that other states share the cost burden which would potentially subject in

- state ratepayers to large cost i ncreases while other states would likely see displacement of fossil resources at no cost.

Commenters also noted that South Dakota has already reached its regional RE target, with 2,915 GWh of RE generation in 2012, and thus its obligation under the target is capped at its share of the 15% regional RE target, 1,819 GWh of RE generation. Commenters noted, however, that15 under the A lternative RE A pproach, South Dakota's obligation under the target is not capped and instead, South Dakota's state

- level 2030 gener ation target, excluding existing hydropower, is 19,156 GWh of RE generation. Commenters stated that including South Dakota's generation target ba sed on the A lternative RE A pproach causes South Dakota's final rate

- based CO2 emission performance goal to decr ease from 741 pounds CO2/MWh under EPA's proposed approach to 185 pounds CO2/MWh under the A lternative RE A pproach. Commenters stated that the percent reduction in South Dakota's state emission rate

-- a state with one of the lowest CO2 emissions rate in t he nation

-- that the proposed rule requires would increase from 35% to 84 % if the EPA were to adopt the A lternative RE A pproach for quantifying RE for BSER

. Commenters stated that applying the A lternative RE A pproach to EPA's calculation of state

- wide emi ssion goals has a profound impact on the current proposed goals and that this is particularly true for a state which has already reached its regional RE generation target under EPA's proposed approach

.
Commenters stated that a better approach in setting a n RE target would consider resource availability, market constraints, reliability impacts, operational constraints, infrastructure requirements, and electricity demand in establishing the goal for each state and therefore recommended that each state undert ake its own proceeding to consider the factors listed above and develop a target that is achievable.

Comment 1 4 : Commenters supported the Proposed RE Approach instead because it takes into account states' existing RPS and grows renewable energy incrementally each year, allowing for a transition to a more diverse energy portfolio.

Response 1 4 : The final building block 3 methodology does not rely on state

- specific deployment estimates, but rather cost

- effective RE at an interconnection level

. The s tringency associated with building block 3 target generation levels for each interconnection is assigned to all of the affected sources within that interconnection

. Specific to these c ommenters concerns, the final methodology provides a greater transitiona l period in a number of ways, most notably by delaying the first year of compliance to 2022 and phasing in the target generation levels over time

. The EPA addresses considerations related to the technical feasibility and associated grid integration costs o f significant RE penetration in both the preamble (section V.E) and GHG Mitigation Measures TSD.

The following are summaries of the specific public comments under this comment:

Commenters stated that EPA's Alternative RE Approach offers no transition for Missouri and ignores the RPS established by Missouri and other states. Commenters supported the Proposed RE Approach instead because it takes into account states' existing RPS and grows re newable energy incrementally each year, allowing for a transition to a more diverse energy portfolio.

Comment 1 5 : Commenters stated that EPA cannot use IPM to set federally enforceable state goals without making the data, calculation steps, assumptions, a nd all other aspects of IPM transparent and accessible to the public

.16 Response 1 5 : The final building block 3 methodology does not rely on state

- specific deployment estimates, but rather cost

- effective RE at an interconnection level

. The basis for buildin g block 3 target generation levels is the observed pattern of historical development for each of the BSER RE technologies

. Modeling projections remain an important aspect of the overall methodology in validating the technical feasibility and cost

- effective ness of the target generation level. The data, assumptions, methodology, and outputs associated with relevant IPM projections are available on the EPA’s power sector modeling website, http://www.epa.gov/airmarkets/powersectormodeling.html www.epa.gov/powersectormodeling

. The EPA addresses considerations related to the technical feasibility and associated grid integration costs of significant RE penetration in both the preamble (section V.E) and GHG Mitigation Measures TSD

The following are summaries of the specific public comments under this comment:

Commenters stated that EPA cannot use IPM to set federally enforceable state goals without making the data, calculation steps, assumptions , and all other aspects of IPM transparent and accessible to the public. Commenters stated that that using IPM to make projections of the level of renewable energy assumed to be economic for a state and then incorporating those projections directly into th e state goal calculations does constitute using IPM to set enforceable limitations on the states. Commenters stated that states are unable to evaluate the validity of IPM's assumptions and predictions unless EPA makes all data inputs, calculations, assumpt ions, and all other factors used in the IPM model transparent and accessible to the states. Commenters stated that EPA should not use a "black box" modeling program to establish regulatory emission standards, particularly when, as here, that was not the or iginal purpose for which IPM was developed and the EPA has provided no assurance that all factors relevant for establishing enforceable requirements on either the states or the electric utility sector are being evaluated and weighted appropriately by IPM. Commenters stated that EPA's Alternative RE Approach is biased in favor of states with very low technical potential for renewable energy and allows EPA to default to its IPM predictions for states like Texas.

Comment 1 6 : Commenters stated that neither of the alternative RE approach calculations provide a reasonable method to determine achievable RE generation targets for states

. Response 1 6 : The final building block 3 methodology does not rely on state

- specific deployment estimates, but rather cost

- effec tive RE at an interconnection level

. The basis for building block 3 target generation levels is the observed pattern of historical development for each of the BSER RE technologies

. Modeling projections remain an important aspect of the overall methodology in validating the technical feasibility and cost

- effectiveness of the target generation level

. The EPA’s final methodology does not include the technical potential limiter referenced by the
commenter s

. Further, there is no misalignment between goal

- setting and compliance because all of the RE technologies used to set the RE target generation level (onshore wind, utility

- scale solar PV, geothermal, and hydropower) are fully creditable compliance resources. For the EPA’s response to this comment, see section V.E of the final rule preamble of the CPP and chapter 4 of the GHG Mitigation Measures TSD for CPP Final Rule.17 The following are summaries of the specific public comments under this comment:

Commenters stated that neither of the Alternative RE Approach calculations provide a reasonable method to determine achievable renewable energy generation targets for states.

Commenters stated the approach that relies on the NREL GIS

- based study would arb itrarily apply a set of uniform benchmark development rates to all states across the country without considering whether the states used to set the benchmark rates for each technology type are representative of the rest of the country. C ommenters stated EP A would not consider factors that may lead some states to develop specific renewable energy technologies more than others. C ommenters also stated this approach adds estimated renewable energy potential across various technology types, even though the NREL study warns (and EPA acknowledges) that these estimates cannot be added together because they may double count available land for use by multiple renewable energy technologies. C ommenters also stated the IPM

- based approach is arbitrary because EPA does not provide any justification for its assumptions regarding reduced costs for new renewable energy generation.

Commenters stated that both approaches fail to recognize the time and resources necessary to deploy additional renewable resources as well as potent ial constraints that could limit siting in certain locations. Commenters noted that these include consideration of environmental

- related issues that affect new site development for renewables and therefore, constructing significant additional wind resource s prior to 2020 may not be feasible and could come at significantly higher cost premiums.

Commenters stated that EPA's misalignment between renewable generation reflected in a state's goal

- setting calculation and the renewable generation available for comp liance with the emissions goals must be corrected; however, the commenters do not believe that either the Alternative RE Approach or the Proposed Approach appropriately resolve this misalignment. Commenters recommended that EPA resolve that concern by allo wing each state to receive full credit for the renewable energy resources developed within its borders, to the extent it decides to finalize either of those two approaches.

Comment 1 7 : Commenters stated that they prefer the Proposed RE Approach over the Alternative RE Approach.

Response 1 7 : The final building block 3 methodology does not rely on state

- specific deployment estimates, but rather cost

- effective RE at an interconnection level

. The basis for building block 3 target generation levels is the observed pattern of historical development for each of the BSER RE technologies

. Modeling projections remain an important aspect of the overall methodology in validating the technical feasibility and cost

- effectiveness of the target generation level

. Final ly, The BSER is forward

- looking in identifying cost

- effective opportunities for emission reductions from 2012; however, the cost and availability of these emission reduction opportunities is the result of many factors, including previous actions. The final building block 3 methodology is described in detail in V.E of the preamble and in the GHG Mitigation Measures TSD.

The following are summaries of the specific public comments under this comment:18 Commenters stated that they prefer the Proposed RE Approach over the Alternative RE Approach. Commenters stated that the Proposed Approach will more effectively set a market signal for renewables and increase opportunities for deployment. However, the commenters stated that they are pleased that the Alternative RE Approach evaluates costs through the Integrated Planning Model, which examines the unsubsidized costs of energy. C ommenters stated that using a levelized cost factor ensures that all renewables are evaluated evenly.

Commenters supported the current method that EPA uses to calculate the renewable generation goal in the proposed rule, and do not support any alternate calculation that does not allow Iowa to receive credit for its early action and billions of dollars of investments in renewable energy. Commente rs noted that under the Alternative RE Approach, Iowa would have to double the amount of renewable energy it currently produces, up to 54% percent of its 2012 generation. Commenters also not ed that for some states, EPA's A lternative RE A pproach results in increases in renewable energy generation that exceed the total amount of all electricity generation reported in that state in 2012 which is not plausible. Commenters stated that the alternative methodology relies on complex technical and economic analyses which depend on highly subjective input values that have not been fully vetted yet. Commenters concluded that it is unnecessary for EPA to use this alternative methodology for a state like Iowa, because Iowa has already started on the trajectory to meet it s 1,301 lbs/MWh goal due to its early action in renewables and energy efficiency.

Commenters stated that EPA should not pursue the proposed renewable potential described in the TSD in the final rule and that EPA's proposed approach based on state RPS targe ts is a better pathway. Commenters noted that the flaws in the RPS approach, such as inadequately rewarding early action, can be largely resolved by the rule changes that the c ommenters and other stakeholders have proposed elsewhere.

Commenters said that d ue to the overestimation of available land and solar power densities, the quantity of renewable energy relied upon by EPA in its alternative renewable proposal is not a reliable indicator of actual renewable potential and recommended that EPA retain its in itial proposal of estimating renewable development based on existing renewable RPSs.

Commenters stated that the Alternative RE Approach was less stringent than the Proposed Approach, which would only limit Wisconsin's potential for greater carbon pollution reductions and public health benefits. Commenters also noted that the Alternative RE Approach has a short compliance window, which would provide less time for states in implementing their plans and may prove to be a burden for overall compliance.

Comment 1 8 : Commenters opposed the application of any other alternative approaches for Building Block 3, including any methodology ba sed on a percentage of the electric demand within the Navajo Nation. Commenters recommended that EPA use its proposed approach for the states, which is to apply an annual growth factor to 2012 baseline RE generation, which will result in no additional emis sion reductions requirements for the Navajo Nation.19 Response 1 8 : The final building block 3 methodology does not rely on state

- specific deployment estimates, but rather cost

- effective RE at an interconnection level

. The basis for building block 3 target ge neration levels is the observed pattern of historical development for each of the BSER RE technologies

. Modeling projections remain an important aspect of the overall methodology in validating the technical feasibility and cost

- effectiveness of the target generation level

. Finally,
t he BSER is forward

- looking in identifying cost

- effective opportunities for emission reductions from 2012; however, the cost and availability of these emission reduction opportunities is the result of many factors, including prev ious actions. The final building block 3 methodology is described in detail in V.E of the preamble for CPP Final Rule and in the GHG Mitigation Measures TSD.

Comment 1 9 : Commenters supported the alternative RE approach and stated that it may provide

more realistic and achievable goals given both the cost and timelines for such projects

. Response 1 9 : The final building block 3 methodology does not rely on state

- specific deployment estimates, but rather cost

- effective RE at an interconnection level

. The bas is for building block 3 target generation levels is the observed pattern of historical development for each of the BSER RE technologies

. Modeling projections remain an important aspect of the overall methodology in validating the technical feasibility and cost

- effectiveness of the target generation level. The EPA addresses considerations related to the technical feasibility and associated grid integration costs of significant RE penetration in both the preamble (section V.E) and GHG Mitigation Measures TSD

The following are summaries of the specific public comments under this comment:

Commenters applauded EPA for including this Alternative RE Approach, which may provide more realistic and achievable goals given both the cost and timelines for such projects. Commenters recognized that the renewable energy potential for both residential and commercial applications is substantial, but the planning and implementation of a comprehensive approach to tap into this generation will be challenging given the timelines involved in the proposed rule. However, c ommenters also believed that the arbitrary application of geographic renewable energy capabilities based on largely unproven renewable portfolio standards of selective states is not appropriate. Commenters noted spe cific challenges that they face involving certain projections from EPA and other federal agencies regarding the development and availability of renewable energy assets and the upfront cost for many of these projects. Commenters recommended that EPA allow i ndividual states the option to select the alternative renewable energy approach, if it should be more suitable to a state's given circumstances in the final rule. Commenters also believed that this flexibility should be provided to states that have already achieved significant reductions in their carbon intensity and to states that have more substantial reduction requirements under the rule

.20 Comment 20 : Commenters stated that because of shortcomings in the assumptions and methodology, the proposed Alterna tive RE Approach significantly underestimates the level of
cost

- effective renewable energy that each state can achieve by 2030

. Response 20 : The final building block 3 methodology does not rely on state

- specific deployment estimates, but rather cost

- effective RE at an interconnection level

. The basis for building block 3 target generation levels is the observed pattern of historical development for each of the BSER RE technologies

. Modeling projections remain an important aspect of the overall me thodology in validating the technical feasibility and cost

- effectiveness of the target generation level

. The EPA’s final methodology does not include the technical potential limiter referenced by the
commenter s . For the EPA’s response to this comment, see section V.E of the final rule preamble of the CPP and chapter 4 of the GHG Mitigation Measures TSD for CPP Final Rule

. The following are summaries of the specific public comments under this comment:

Commenters stated that the benchmark generation calculati on under the Alternative RE Approach assumes no technological innovation. Commenters stated that because of shortcomings in the assumptions and methodology, the proposed Alternative RE Approach significantly underestimates the level of cost

- effective renew able energy that each state can achieve by 2030. Therefore, c ommenters supported adopting a version of the Alternative RE Approach that corrects these limitations. Commenters stated that one way to address a number of the shortcomings would be for EPA to i ncorporate historical market growth rates into the projections of achievable renewable energy growth. Commenters also stated a viable approach to implementing this type of methodology utilizing market data over the last five years was recently outlined in the brief entitled, Strengthening the EPA's Clean Power Plan, authored by The Union of Concerned Scientists

.
Commenters stated that the Alternative RE Approach caps the amount of generation expected from each evaluated technology type for each state using the development rate of that technology in the top states in 2012 (deemed "benchmark generation"). Commenters stated that the estimated 2030 benchmark generation for each technology type is driven primarily by the amount of generation from that technology in 2012 rather than by a projection of the technically and economically recoverable generation from that sourc e in 2030. Commenters stated this assumption is unreasonable as the amount of generation from most renewable technologies increases each year, often significantly. Commenters provided the example that net generation from solar PV increased nationally from 3,451 GWh in 2012 to 8,327 GWh in 2013. Commenters stated because EPA uses 2012 rather than 2013 data to calculate the solar development rate, the Alternative RE Approach already underestimates the utility

- scale solar development rate of the top 16 states by over 100 percent. Commenters stated that using 2013 data shows benchmark generation for solar of 80,000 GWh rather than the 34,000 GWh used in the Alternative RE Approach, underestimating achievable utility

- scale solar generation by a factor of almost 2 .4 in just one year. Commenters stated that similar underestimation of achievable generation occurs for the other renewable energy technologies EPA evaluates.

Commenters stated that for the above reasons, it makes little sense to cap 2030 renewable
genera tion based on the 2012 level of deployment, even if that level is derived from the performance of top states and while top states were likely capturing an achievable and cost

-21 effective portion of technical potential renewable generation in 2012 based on cu rrent costs and technological development, given the scale of the resource availability in a number of states, they are unlikely to have captured all achievable and cost

- effective renewable generation in 2012. Moreover, c ommenters stated that the portion o f each renewable resource that is achievable and
cost

- effective has already increased since 2012

-- a trend that will surely persist as technology costs continue to drop and performance continues to improve.

Comment 2 1 : Commenters disagreed with EPA's quant ification of RE generation under the Alternative RE Approach of using of a single development rate derived from the top 16 States in the country.

Response 2 1 : The resources and data provided in this comment were valuable in finalizing the building block 3 methodology. The final building block 3 methodology does not rely on state

specific deployment estimates, but rather cost

- effective RE at an interconnection level

. The basis for building block 3 target generation levels is the observed pattern of historical development for each of the BSER RE technologies

. Modeling projections remain an important aspect of the overall methodology in validating the technical feasibility and cost

- effectiveness of the target generation level

. The EPA’s final methodolo gy does not include the technical potential limiter referenced by the above commenters . For the EPA’s response to this comment, see section V.E of the final rule preamble of the CPP and chapter 4 of the GHG Mitigation Measures TSD for CPP Final Rule

.
The f ollowing are summaries of the specific public comments under this comment:

Commenters disagreed with EPA's quantification of RE generation under the Alternative RE Approach of using of a single development rate derived from the top 16 States in the country

.
Commenters recommended to better reflect the capability of the technologies and to establish an approach that is more consistent with the approach taken for other BSER technologies, that EPA calculate the benchmark development rate of utility

- scale wind and solar using the experience of the top six states. Commenters stated that in calculating the benchmark development rate for utility

- scale solar and onshore wind, the Alternative RE Approach utilizes the development rate of the 16 states with the highes t penetration of that technology, i.e., roughly the top third of states, while the development rate for geothermal is based on the top 6 states. However,

c ommenters said the Alternative RE Approach does not justify why it is appropriate to deem the top 16 states as the "best" performers for solar and wind, nor does it justify the different number of states used for geothermal. Commenters stated that analysis of the top 16 states shows huge variation across the states, as among the 16 states with the highest development rates for onshore wind, the bottom 3 states had a development rate of 3 percent, while the top 3 states had a development rate of 23 percent. As such, c ommenters stated it is difficult to argue that all 16 states should be used for wind and so lar, particularly when other portions of the Clean Power Plan utilize smaller numbers of states to more accurately establish technically feasible best practice. Commenters stated that beyond geothermal, the Proposed Rule bases the best

- practices level of a chievable annual incremental energy efficiency on the performance of three states and the anticipated achievement of an additional nine states. Commenters stated that the choice of the22 number of states used to calculate the benchmark development has large implications for the ultimate renewable energy growth assumptions. Commenters stated that averaging across 16 states produces benchmark development rates of 0.009 percent and 9 percent, respectively, for utility

- scale solar and wind, while averaging the to p 6 states would increase respective rates to 0.02 percent and 17 percent. Commenters stated that applying these higher development rates to the Alternative RE Approach increases total benchmark generation from 35,434 GWh to 129,041 GWh (264 percent increa se) and onshore wind generation from 2,831,947 GWh to 7,221,230 GWh (155 percent increase).

Commenters noted that the reason the benchmark approach is producing unrealistically large potential renewable energy results for some states is because the EPA has failed to recognize the drastic difference in the development rate of renewables between states with very low technical potentials versus states with very large technical potentials. Commenters stated that all 16 states that EPA used to set the benchmark for wind renewable energy have technical potentials in the NREL report less than 100,000 GWh ; however, there is a clear distinction in the development rates for wind between states with very low technical potentials versus states with technical potentials greater than 1,000,000 GWh. Commenters noted that the development rate for states with a technical potential for wind greater than 1,000,000 GWh averages only 0.32% and the maximum rate is only 0.81%; thus there is no rational basis for EPA's assumption th at states with the lowest technical potentials can or should set the benchmark for other states with very large technical potentials. Commenters stated that EPA failed to consider that a small amount of generation in a state with a very low technical poten tial will result in a larger percent development rate, as EPA included Delaware, a state with only 22 GWh of technical potential for wind generation, into the benchmark average. Commenters stated that it is irrational for the EPA to believe that a state su ch a Delaware is appropriate to be used even in part to set a benchmark for states with exponentially larger potential for renewable energy. Commenters stated that the result of EPA's flawed approach to setting benchmarks in the Alternat iv e RE Approach is that EPA would default to the IPM predictions for all states with technical potentials greater 1,000,000 GWh as well as many other states. However, c ommenters added that EPA has provided no demonstration of IPM's accuracy and reliability f or predicting both the economic and technological feasibility of expanding renewable energy generation on a state

- by

- state basis and noted that IPM was developed to evaluate the impact of regulations on the electric utility sector, not to establish enforce able limitations.

Commenters specifically stated that EPA's use of the benchmark states to determine potential development rates for wind energy in the North Central states is inappropriate. Commenters noted that not a single benchmark state is located in the North Central region, the region with the greatest wind resources in the country. Commenters noted that the benchmark state with the highest potential (California) has a potential only 62% of the lowest potential North Central state (Michigan) and in contrast, the technical potential for wind in South Dakota is over 100,000 times higher than that of Delaware (which has a benchmark development rate of 17%). Commenters stated that there is no reason to believe South Dakota should be able to develop its

w ind resources to anything like the scale achieved by the much smaller potential state of Delaware, or even of California, which has 1/30th the wind potential of South Dakota spread out over a much larger area and integrated into a much larger power system. Commenters suggested that EPA can resolve the barriers and difficulties North Central states will face when integrating23 large amounts of intermittent wind energy under this approach by evaluating the development rate on a regional, not national, basis.

Co mmenters stated that applying a benchmark determined largely by states with the lowest RE potential to all states, including those with the highest RE potential, requires unrealistic RE deployment from states with the greatest RE potential. Commenters stat ed that if EPA determined benchmarks based on the development rates of the benchmark states in the top third for solar potential, the benchmark rate would be 0.003 percent, not 0.009 percent and for wind, this calculation is not even feasible because no st ates in the top third for NREL wind potential contribute to the wind benchmark rate. Commenters concluded that it is simply unreasonable to ask states to meet a performance rate that no states with significant NREL potential have come close to meeting.

Com menters noted that states that have achieved the largest proportion of their RE technical potential are those states with the following conditions: they have a deep supply of relatively low cost RE sources to exploit; a good deal of that energy is in agric ultural areas that are eager for money from these resources; the resources are not close to large population centers and the development of the resources have not reached a level to arouse strong local political opposition; while at the same time not achie ving an amount of development to run into transmission constraints, which when hit, will constrain further resource development; or the state has a strong ideological preference toward supporting clean energy. Commenters stated that assuming that states wi th these conditions should be the basis for a benchmark for the rest of the U.S. ignores the large differences that exist between states in terms of the type of renewables endowment, population density, primary economic drivers, and political support/oppos ition to these technologies.

Commenters questioned if the top 16 states are sufficiently representative or whether they are likely to have the greatest renewable potential for a given renewable resource. If the latter, Commenters wondered how that fact tha t the other states may not have sufficient resource potential and/or ability to deliver the energy at a given penetration level to achieve the benchmark development rate had been addressed in this approach.

Commenters wondered why, if EPA believes separat ing the country into regions is important to account for differences in renewable energy potential, does the agency also believe all states can mirror the renewable energy profiles of the sixteen states with the most installed capacity of each specific tec hnology? Commenters noted that because the Agency uses a generic and unrealistic benchmark rate in its calculations, Indiana's ren ewable energy target under the A lternative RE A pproach is 20 percent of the state's electricity generation by 2030 which is ne arly three times the number yielded by the agency's first approach.

Commenters stated EPA's reliance on historic renewable energy development in the top 16 states skews the resulting benchmark renewable energy development rate for the nation as those state s have been the most successful in developing renewable resources due to high resource potential and low development costs. Commenters stated EPA has not explained why it is appropriate to assume that the historical development rate in a select group of st ates is replicable, sustainable and achievable for all states. C ommenters stated prior growth of renewable resources is not necessarily an indication of future growth.24 Commenters stated that a state

- specific analysis of RE development potential that takes into account each state's unique circumstances would provide more appropriate RE generation goals for each state than a development rate using the top 16 states.

Commenters stated rather than averaging the development rates of the top 16 states, EPA could instead rely on an average of the top 5 states for each technology; this would more than double the benchmark development rates for both utility

- scale solar and onshore wind. Commenters noted there would be no impact on the benchmark development rate for geothermal, as only 5 states reported geothermal generation in 2012. Commenters stated that the second step of EPA's proposed alternative methodology would still ensure that only the economical renewable generation potential in each state is counted. Comme nters observed that the application of the "top 16 state benchmark" is unduly limiting with respect to the technical potential of renewable technologies in each state

- particularly in regard to the development of utility

- scale solar. Commenters suggested adding a development cost ceiling in terms of $/MWh to this suggested modification to the benchmark development rate which would ensure that only the cost

- effective renewable generation in each state is targeted.

Commenters requested that EPA use all state s to develop an average benchmark development rate, not just the top 16 states, in order to more realistically account for differences in renewable potential among states. C ommenters noted that this approach would provide a better estimate of what may be a chievable across the country, grounded in what has been demonstrated as achievable in the past.

Commenters asked that EPA allow each state to determine appropriate targets for renewable energy development given the physical environment, existing resources and infrastructure, and the broader economic conditions prevailing within each state. Commenters stated tha t to the extent EPA retains its A lternative RE A pproach to renewable energy at all, that approach should be optional and only employed at the sole discretion of each individual state. Commenters stated that although providing states that level of flexibili ty may allow states to make decisions regarding renewable energy targets that could affect the goals for the state, Commenters believed that approach would be consistent with the provision of Section 111(d) that allows states to determine the "standards of performance" for existing units.

Comment 2 2 : Commenters stated that the EPA relies on outdated capacity and generation data in its Alternative RE Approach methodology, and urged EPA to update this information.

Response 2 2 : The resources and data provided in this comment were valuable in finalizing the building block 3 methodology, particularly in the adoption of updated cost and performance data for onshore wind and solar resources

. There is no technical potential limiter in the final methodology, which is described in section V.E of the preamble and in the GHG Mitigation Measures TSD

. The following are summaries of the specific public comments under this comment:25 Commenters stated t hat EPA relies on outdated capacity and generation data in its Alternative RE Approach methodology, and urged EPA to update this information. Commenters commended EPA on using technical and economic data to calculate the state renewable energy potential, b ut noted that EPA has weakened its approach by relying on outdated and inaccurate data, such as EIA AEO 2013

. C ommenters stated that when applying the Alternative RE Approach, EPA should use the most reliable and up

- to

- date cost and performance assumptions available, which provide a more accurate representation of the cost competitiveness of renewables and demonstrate that more renewables can be deployed at reasonable cost.

Commenters stated that if EPA continues to utilize its benchmark rate methodology w ithin the Alternative RE Approach, EPA should use updated data on installed capacity and generation and noted that there has been significant growth in wind and solar capacity and generation since 2012, which will continue to grow between now and 2017 when the standards take effect.

Commenters believed that the EIA data used by EPA does not reflect current performance estimates within the solar market and recommended using the maximum capacity factor in each state, as utility scale developers will target t he highest resource regions. Commenters noted that other approaches, such as the Union of Concerned Scientists' demonstrated renewables growth approach which uses actual generation data from 2013 and adds projected generation from wind and utility

- scale so lar projects known to be under construction through 2016, show double the amount of renewable energy potential than EPA's analysis.

Commenters note d that EPA's methodology for evaluating the performance of onshore wind and solar PV, as described in section 4.4.5 of the EPA's "Power Sector Modeling Platform v.5.13" document, is reasonable but that some of the data appear outdated, especially for onshore wind. Commenters noted that using EIA's preliminary data for 2013 one finds that wind generation for the 4 7 states analyzed by EPA is approximately 166,787 GWh, which is a 19% increase over the 2012 wind generation of 140,299 GWh. Commenters also noted that using EIA's preliminary monthly data for the first 8 months of 2014 one finds that wind generation for t he 47 states analyzed by EPA is 9% higher than the same 8 months in 2013. Lastly, c ommenters added that using the same data sets for solar one finds that 2013 solar generation is 8,575,710 GWh, a 99% increase over 2012 solar generation and the first 8 mont hs of 2014 show 128% increase in solar generation relative to the same 8 months of 2013.

Commenters stated that EPA's estimated wind energy potential relies on data from 2010 that does not represent the current state of the wind industry, nor will it repre sent the technological advancements available between now and 2030. Commenters noted, for instance, that EPA's plan estimated wind energy that relied on hub heights of 80 meters when the average wind turbine hub height installed in 2012 was 100 meters. Com menters noted the large impact of taller wind turbines as, for example, Tennessee's estimated wind energy resources are approximately eighty

three times greater (over 25,000 megawatts of potential) when conducting a resource assessment using a 140

- meter to wer, as opposed to an 80

- meter tower (approximately 300 megawatts of potential).

Commenters noted that the NRDC engaged with ICF recently to run the IPM to reproduce EPA's RE Market Potential run using up

- to

- date cost and performance assumptions for renewa ble technologies. Commenters stated that the resulting national target for renewable generation26 nearly doubles from EPA's approaches, growing from 520

- 530 TWh to 930 TWh

, which the

c ommenters believe clearly demonstrated that significantly higher levels of renewable energy are both technically and economically achievable, compared to the levels proposed in either of EPA's target

- setting approaches. Commenters urged EPA to strengthen its renewable energy targets to reflect the full potential of these technologies.

Commenters noted that the technical potential is based on the 2012 penetration rates for each renewable technology in the top third of states, and so assumes no technological advancements or cost reductions between now and 2030. Commenters al so noted the underlying National Renewable Energy Labs report used to determine the technically feasible renewable generation in each state uses outdated technology assumptions that underestimate the amount of installable capacity and the generation for ea ch MW of installed capacity. Commenters stated that the energy market

- based cap that EPA places on the level of renewable generation deemed achievable uses inflated cost figures, failing to account for the expected level of cost reductions over time. Lastl y, c ommenters stated that both the technical potential and energy market

- based caps treat some renewable resources such as biomass and hydroelectric generation inconsistently and fail to include the potential to add new sources of generation from these re sources.

Commenters noted that there has been significant growth in wind and solar capacity and generation since 2012, and this capacity will continue to grow between now when the standards take effect which highlights the need for utilizing up

- to

- date dat a.

Comment 2 3 : Commenters recommended that EPA update the cost and performance data used in IPM modeling to support the Alternative RE Approach

. Response 2 3 : The resources and data provided in this comment were valuable in finalizing the building block 3 methodology

. The EPA has updated cost and performance assumptions for onshore wind and solar resources in addition to removing the technical potential limiter. The final methodology is described in section V.E of the preamble and in the GHG Mitigation Measures TSD

. The following are summaries of the specific public comments under this comment:

Commenters recommended that EPA update the cost and performance data used in IPM modeling to support the Alternative RE Approach. Commenters stated that the cos ts of RE, specifically onshore wind and solar PV, are overstated. Commenters noted that for onshore wind, the 2016 capital cost is estimated at $2,258/kW (in 2011 $) which actually represents peak wind project pricing circa 2009

- 2010 and not the current st ate of technology and cost. Commenters further noted that according to the DOE the average installed project cost for wind in 2009

- 2010 was approximately $2,230/kW, however, due to technological advances and a more efficient supply chain the average instal led cost of wind in 2013 was $1,630/kW. Commenters stated similar trends for solar PV. Commenters urged EPA to allow for

more significant continued technology improvements, commit to periodically revisiting the calculation of RE generation targets, or both

. Commenters stated that the regional cost cost adjustments utilized by EPA, as found in section 4.4.4 and Table 4

- 15 of the EPA's "Power27 Sector Modeling Platform v.5.13" document appear to be reasonable so long as the general cost assumption to which they are applied is corrected. Commenters also stated that EPA's use of multipliers similar to the long

- term multipliers from EIA's NEMS model to capture difference in capital cost of new wind capacity is a reasonable premise and that the four cost categories used for onshore wind appear reasonable.

Commenters recommended that EPA adopt the Alternative RE Approach, but suggested that EPA strengthen this approach by using updated cost and performance data for renewable energy technologies. C ommenters noted that the costs used by EPA in its economic approach utilizing IPM are significantly higher than current solar and wind prices. Commenters stated that the IPM economic model should use the most reliable and up

- to

- date cost and performance assumptions available, which will provide a more accurate representation of the cost competitiveness of renewables and lead to increased deployment. Commenters also recommended that EPA request updated renewable resource assessments and cost and performance assumptions from NRE L, update the IPM cost and performance assumptions for onshore wind, base capacity factors for new wind projects on data from recent and studies that reflect recent technology advances, use DOE Wind Vision cost and performance assumptions for offshore wind , include distributed solar PV generation in baseline renewable generation, and finally to include updated assumptions for biopower

.
Commenters stated that EPA could refine its Alternative RE Approach to update the cost and capacity assumptions used in th e IPM modeling and eliminate the benchmark development rate cap that serves as an artificial cap on the RE potential of states.

Commenters believed that incorrect cost and performance assumptions in the IPM have produced low output levels for wind and sola r and that the benchmark development rate also generally results in low capacity target levels.

Comment 2 4 : Commenters noted that EPA's option for states to set renewable energy targets based on each state's technical renewable energy potential is flawed.

Response 2 4 : The final building block 3 methodology does not rely on state

- specific deployment estimates, b ut rather cost

- effective RE at an interconnection level

. The basis for building block 3 target generation levels is the observed pattern of historical development for each of the BSER RE technologies

. Modeling projections remain an important aspect of the overall methodology in validating the technical feasibility and cost

- effectiveness of the target generation level

. The EPA addresses considerations related to the technical feasibility and associated grid integration costs of significant RE penetration in both the preamble (section V.E) and GHG Mitigation Measures TSD.

The following are summaries of the specific public comments under this comment:

Commenters noted that EPA's option for states to set renewable energy targets based on each state's technical r enewable energy potential is flawed because it does not take into account state specific issues, such as zoning, permitting constraints, grid limitations, costs associated with development, reliability concerns, local ordinances, or community acceptance wh ich influence28 the actual deployment of RE generation. C ommenters stated that states with similar technical potential may have vastly different achievable potential and that states should have more flexibility in identifying potential.

Comment 2 5 : Commenters urged EPA to utilize a determination of technically potential renewables in a similar manner to the National Renewable Energy Laboratory (NREL) estimates

. Response 2 5 : The final building block 3 methodology does not rely on state

- specific deplo yment estimates, but rather cost

- effective RE at an interconnection level

. The EPA addresses considerations related to the technical feasibility and associated grid integration costs of significant RE penetration in both the preamble (section V.E) and GHG Mitigation Measures TSD.

The following are summaries of the specific public comments under this comment:

Commenters urged EPA to utilize a determination of technically potential renewables in a similar manner to the National Renewable Energy Laboratory (NREL) estimates of the technical potential of specific renewable electricity generation technologies because of their concern that FERC rules make it difficult to support long term out

- of

- market incentives which will hamstring State's abilities to achieve results through Building Block 3.

Comment 2 6 : Commenters recommended eliminating use of a 'benchmark rate' as the model already utilizes a resource availability curve and cost curve, making the benchmark utilization rate a redundant and unfounded constra int on development.

Response 2 6 : The technical potential benchmark has been eliminated in the EPA’s final methodology for building block 3. For the EPA’s response to this comment, see section V.E of the final rule preamble of the CPP and chapter 4 of the GHG Mitigation Measures TSD for CPP Final Rule.

Comment 2 7 : Commenters stated that EPA should exclude the technical potential benchmark fro m the Alternative RE Approach and rely solely on the IPM model results.

Response 2 7 : The technical potential benchmark has been eliminated in the EPA’s final methodology for building block 3. For the EPA’s response to this comment, see section V.E of the final rule preamble of the CPP and chapter 4 of the GHG Mitigation Measures TSD for CPP Final Rule.

The following are summaries of the specific public comments under this comment:

Commenters stated that EPA should exclude the technical potential benchmark from the Alternative RE Approach and rely solely on the IPM model results, which would produce a more29 accurate representation of likely future development. Commenters noted that EPA has previously relied on the IPM model to analyze the impact of other air emissions policies on the U.S. electric power sector. Commenters noted that the IPM has the potential to not only model technical potential limits, but also to place economic limitations on resource availability within the overall technical potential which the commenters believe can produce a more accurate representation of market dynamics than the proposed benchmark development rates.

Commenters noted that EPA did not use this more granular data in their analysis but recommended that EPA consider using it when determining technical and economic potential for each state and region. Commenters stated that the benchmark development rate places an unnecessary constraint on states that are currently leaders in renewable energy development and that if IPM result s demonstrate that these states can continue to develop their renewable resources at a reasonable cost, then these states' targets should be set accordingly. Instead of using the benchmark rate, c ommenters suggested that EPA consider implementing constrain ts that more closely simulate real

- world grid operations. Commenters noted that there is a growing body of research on grid integration of renewables, and several studies have suggested that at least 30% of renewables can be handled by the existing grid, p roviding that there is adequate transmission expansion and proper system planning.

Commenters noted that EPA has used the IPM model to analyze the impact of air emissions policies on the U.S. electric sector in previous rulings, and argued that the precede nt is therefore to rely solely on the IPM model for setting the renewable targets in each state under the A lternative RE A pproach. Commenters proposed a second alternative which would be to use the demonstrated recent growth rates of renewable energy techn ology as the basis for the benchmark element of the approach rather than absolute 2012 development rates. A third option offered by the c ommenters is that EPA could increase the technical cap to account for technological improvements and cost reductions th at have expanded the quantity of the renewable resource available, particularly in states and regions that appear to have lower quality wind resources at 80 meter hub heights but actually have significant resources at the higher hub heights that are being used in those regions today.

Commenters noted that IPM results already reflect both technical and economic constraints through detailed resource supply curves, which they support. C ommente rs stated that not only does the IPM model contain the same technica l potential limit as NREL's technical potential, but also places economic limitations on resource availability within the overall technical potential, which they felt is a more accurate representation of market dynamics than the benchmark development rates

. Commenters believed that applying NREL's technical potential for solar in each state is arbitrary because it shows the solar capacity that could be built in a given state without recognizing real

world limiting factors such as economic growth and grid c onstraints and therefore, EPA should not rely on NREL's technical potential for setting state goals. C ommenters stated that, unlike the technical potential, the IPM model takes into account the cost of building renewable generation, as well as grid conditi ons in a state and a number of other factors. Additionally, the commenters stated that the IPM model considers the resource potential that is considered by NREL's technical potential and that with the correct solar data inputs, the IPM model can provide a realistic projection of solar energy potential at the state level that can be relied upon for setting30 state goals. C ommenters noted that there is precedent to rely solely on the IPM model for setting renewable targets in each state, as multiple other polic ies solely utilize the IPM model to calculate targets.

Comment 2 8 : Commenters stated that instead of using the benchmark rate, EPA should implement constraints that more closely simulate real

- world grid operations

. Response 2 8 : The resources and data provided in this comment were valuable in finalizing the building block 3 methodology

. The EPA has eliminated the technical potential benchmark rate and instituted constraints at the IPM region level that limits variable, non

- dispatchable RE (solar and win d) to 30% of net energy for load. For the EPA’s response to this comment, see section V.E of the final rule preamble of the CPP and chapter 4 of the GHG Mitigation Measures TSD for CPP Final Rule.

The following are summaries of the specific public comments under this comment:

Commenters stated that instead of using the benchmark rate, EPA should implement constraints that more closely simulate real

- world grid operations. Commenters noted that there is a growing body of research on grid integration of renewa bles, and several studies have suggested that at least 30% of renewables can be incorporated into the existing grid, providing that there is adequate transmission expansion and proper system planning.

Commenters stated that EPA can utilize this constraint at the ISO level, either in modeling or in post

- processing, to account for possible grid integration costs that may arise and which are not fully accounted for in IPM. Commenters noted that this constraint has been modeled in previous versions of IPM (v. 4.10) at 20% of the generation mix.

Comment 2 9 : Commenters recommended that EPA drop the entire technical potential calculation and simply use the market potential to establish RE targets by state

. Response 2 9 : The technical potential benchmark has been eliminated in the EPA’s final methodology for building block 3. For the EPA’s response to this comment, see section V.E of the final rule preamble of the CPP and chapter 4 of the GHG Mitigation Measures TSD for CPP Final Rule.

The following are summaries o f the specific public comments under this comment:

Commenters recommended that EPA drop the entire technical potential calculation and simply use the market potential to establish RE targets by state because the market potential necessarily includes and is limited by the resources that are technically available. Commenters noted that utilizing the top 16 states' development rate in determining the benchmark rate is arbitrary because the results of the rates are clearly counter

- intuitive as the states with t he greatest amount of wind generation have some of the lowest development rates. Commenters stated that eliminating the benchmark rate will essentially result in the market potential analysis31 determining the RE targets which will be necessarily limited by technical potential as the technical resource is an input into the market potential analysis. Commenters stated that by using the EPA's data provided in the Alternative RE Approach data file, eliminating the benchmark rate would result in 442,417 GWh onshore wind target generation in 2030, an increase of 57,591 GWh, or 15% over the target presented by EPA. Co mmenters stated that removing the benchmark rate for solar would result in 27,531 GWh solar target generation in 2030, an increase of 18,809 GWh or 216% over the target presented by EPA and that this significant percentage increase in solar occurs because this technology has such a low benchmark rate of 0.009%.

Comment 30 : Commenters stated that EPA's first two alternatives provided in its Alternative RE Target Approach are not based on sound analytics.

Response 30 : The technical potential benchmark has been eliminated in the EPA’s final methodology for building block 3. For the EPA’s response to this comment, see section V.E of the final rule preamble of the CPP and chapter 4 of the GHG Mitigation Measures TSD for CPP Final Rule.

The following are summar ies of the specific public comments under this comment:

Commenters stated that EPA's first two alternatives provided in its Alternative RE Target Approach are not based on sound analytics and that EPA's definition of the RE development rate as "the amount of existing RE generated in a state divided by its technical potential" is not a suitable metric with which to determine state RE targets. Commenters stated that the metric is not an informative measure of what should be a plausible or economically justifi able level of RE deployment in other states.

Commenters stated that they do not support setting targets based on this definition, and stated that if EPA insists on this type of approach, that it can be improved upon by looking at the amount of RE generated in a state divided by the state's RE economic potential

- or the amount of RE already deployed divided by the amount that IPM model runs indicate would deploy at a defined CO2 price.

Comment 3 1 : Commenters stated that the technical resource cap used in the Alternative RE Approach is redundant, as the economic analysis step already accounts for the quantity and quality of the resource

. Response 3 1 : The technical potential benchmark has been eliminated in the EPA’s final methodology for building b lock 3. For the EPA’s response to this comment, see section V.E of the final rule preamble of the CPP and chapter 4 of the GHG Mitigation Measures TSD for CPP Final Rule.

The following are summaries of the specific public comments under this comment:32 Comme nters stated that the technical resource cap used in the Alternative RE Approach is redundant, as the economic analysis step already accounts for the quantity and quality of the

resource. Commenters noted that experience shows that such a cap is not bindin g as many states have already significantly exceeded the cap proposed by EPA and that imposing any technical resource limit that is less than 100% of the total technical resource would be redundant and an inaccurate representation of the economic factors t hat drive and limit renewable energy development. In the alternative, c ommenters stated that the cap should be raised to account for the fact that larger wind turbines, higher hub heights, and declining costs have expanded the viable wind resource in many states, enabling many states to greatly exceed the MW cap that EPA has proposed.

Commenters noted that in EPA's methodology, the estimated 2030 benchmark generation for each technology type is driven primarily by the amount of generation from that technol ogy in 2012, rather than from a projection of the technically and economically feasible generation from that source in 2030 but stated that in reality, the amount of generation from most renewable technologies increases each year

-- often significantly. Comm enters noted that since the end of 2005, the U.S. wind energy industry has double its installed capacity on average every 36 months and that the industry has experienced a five

- year annual growth rate of 19.5 percent from 2009

- 2013. In addition, c ommenters stated that because each state's target generation from a particular resource type is capped at the proportion of 2012 generation to technical potential for the top states for all compliance years, this underestimation will only increase over time, as con tinuous improvements in renewable technology drive increasing deployment. Commenters used the wind turbine hub height specification to argue that the technical cap is arbitrary. Commenters stated that the 80 meter specification for hub height that EPA used based on the NREL assessment is no longer an industry standard, as c ommenters have confirmed that 31% of the turbines installed in 2012 had hub heights higher than 80 meters.

Commenters also stated that EPA, in its Alternative RE Approach, does not justif y why it is appropriate to deem the top third as the "best" performers. Commenters noted that other portions of the Clean Power Plan utilize smaller numbers of states to more accurately establish technically feasible best practice and when determining the appropriate best

- practices level of achievable annual incremental energy efficiency, the Clean Power Plan deems an incremental savings rate of 1.5 percent as achievable based on the practices of three states and the anticipated achievement of an additional nine states. Commenters stated that it makes little sense to cap 2030 renewable generation based on the 2012 level of deployment, even in the top states because while top states are likely capturing an achievable and cost

- effective portion of technical
po tential renewable generation based on 2012 costs and technological development, that portion will surely increase over time as technology cost and performance continue to improve, particularly for states with lower quality wind resources that are dispropor tionately benefiting from taller towers and other low

- wind

- speed turbine technologies.

Commenters stated that if EPA continues to impose a cap, it should rely on the results of recent renewable integration studies done by utilities, grid operators, NREL an d other government agencies as these studies have found that penetrations of variable renewable energy resources of 40

- 50 percent are achievable on a state and regional level, with modest integration costs. Commenters noted, for example, that NREL's Renewa ble Energy Futures study examined a case in which wind and solar provide nearly 50 percent of total U.S. electricity generation by 2050,33 the Nebraska Power Association wind integration study found minimal integration costs and no reliability concerns assoc iated with wind providing 40 percent of electricity in the Southwest Power Pool, and the Minnesota Department of Commerce just released a comprehensive study that found no challenges to integrating 40 percent wind and solar energy in Minnesota, including

a detailed examination of power system dynamics and other essential reliability services.

Comment 3 2 : Commenters believed that EPA should include a "floor" for renewable energy in its Alternative RE Approach methodology

. Response 3 2 : The final building bl ock 3 methodology does not rely on state

- specific deployment estimates, but rather cost

- effective RE at an interconnection level

. The stringency associated with building block 3 target generation levels are assigned to all affected sources within that inte rconnection. The final building block 3 methodology is described in detail in V.E of the preamble and in the GHG Mitigation Measures TSD.

The following are summaries of the specific public comments under this comment:

Commenters believed that EPA should include a "floor" for renewable energy in its Alternative RE Approach methodology. Commenters stated that EPA should include a floor for each state that is based on its current non

- hydropower renewable generation, increa sed at a minimum but achievable growth rate (e.g. 3% annual growth) to account for additional development of renewable energy sources between now and 2030. Commenters stated that the minimum growth rate could be conservatively established based on recent g rowth trajectories as reported by the U.S. Energy Information Administration.

Commenters stated the alternative RE proposal results in a renewable energy target for 12 states that is less than the actual renewable energy generation reported by these same s tates in the 2012 baseline year. Commenters stated in recognition of this technical limitation of the proposed alternative methodology, EPA should implement a "floor" derived from a conservative historic 10

- year national compound average growth rate for re newable resources as reported by the U.S. Energy Information Administration's Annual Energy Outlook 2014.

Comment 3 3 : Commenters suggested that EPA establish a "ceiling" in its Alternative RE Approach methodology.

Response 3 3 : The final building block 3 m ethodology does not rely on state

- specific deployment estimates, but rather cost

- effective RE at an interconnection level

. The stringency associated with building block 3 target generation levels are assigned to all affected sources within that interconnec tion. The EPA addresses considerations related to the technical feasibility and associated grid integration costs of significant RE penetration in both the preamble (section V.E) and GHG Mitigation Measures TSD.

The following are summaries of the specific public comments under this comment:34 Commenters suggested that EPA establish a "ceiling" in its Alternative RE Approach methodology. Commenters stated the A lternative RE A pproach more realistically bounds the renewable energy analysis, however, further cei ling requirements based on operational considerations should also be included. Commenters stated energy, especially from intermittent sources, is not directly comparable to the energy produced from traditional energy resources (e.g., coal, nuclear, gas). C ommenters stated factors such as reliability, ability to dispatch on demand, and predictability/consistency of energy patterns must all be considered. Commenters stated this is not only the case on an individual plant basis, but also from a system

- wide
per spective. Commenters stated therefore, ceilings should also be governed by utility dispatch principles, considering impacts from generation and transmission of energy across an integrated electrical system.

Commenters stated that EPA should consider a ceil ing for each state's renewable energy target if the Agency does not pursue a regional application. Commenters noted that this ceiling could be limiting a state's renewable energy target to its 2012 generation from all sources, which will allow for existing progress to be reflected in the targets.

Comment 3 4 : Commenters believed that EPA should modify the a lternative RE a pproach to provide credits for states that have adopted and implemented updated building code policies.

Response 3 4 : For the EPA’s response to this comment, see section V.A of the final rule preamble of the CPP.

The following are summaries of the specific public comments under this comment:

Commenters believed that EPA should modify the Alternative RE Approach to provide credits for s tates that have adopted and implemented updated building code policies. Commenters noted that adopting and implementing energy conservation construction standards such as the 2009 IECC building code standards for commercial and residential buildings and th e 2012 IECC standards are always a challenge for their state, and the energy efficiency savings do have a significant positive impact on South Carolina's energy consumption. Commenters stated that EPA should consider how building code energy efficiency sav ings could be calculated to provide credits towards South Carolina's emission reductions.

Comment 3 5 : Commenters stated the cost and performance assumptions in the Alternative RE Approach inaccurately represent renewable energy technologies

. Response 3 5 : The resources and data provided in this comment were valuable in finalizing the building block 3 methodology

. The EPA updated cost and performance assumptions for both onshore wind and solar resources in the final methodology, which is described in detai l in V.E of the preamble and in the GHG Mitigation Measures TSD.

The following are summaries of the specific public comments under this comment:35 Commenters stated the cost and performance assumptions in the Alternative RE Approach inaccurately represent renewable energy technologies

. Commenters stated EPA provides very little detail on how it conducted the IPM projection for each resource. Commenters also stated EPA does not specify why new renewable generation capacity costs were reduced by a fixed

amoun t over time and across resources, why $30 per MWh is the appropriate amount, or the significance of "up to" in "up to $30 per MWh." Commenters requested further clarification on EPA's methodology with regard to the IPM

- projected generation cap for each res ource.

Commenters stated that the A lternative RE Approach TSD says that "the cost reduction in new RE is intended to represent the avoided cost of other actions that could be taken instead to reduce power sector CO2, and to reflect continued reductions in RE technology costs." Commenters applauded EPA for using a modified modeling scenario that reflects renewable energy cost reductions compared to the IPM base case scenario. However, c ommenters stated that the underlying base case cost data so significantl y overestimate current and future renewable energy costs that it is unlikely the adjustments implemented by EPA to create the modified scenario are sufficient. Commenters stated that for example, solar PV capital cost assumptions for 2016 in the IPM base c ase are $3.364 per W, compared to an average of $1.7 to $1.8 per W observed already in 2014. Furthermore, c ommenters stated, IPM assumes that solar PV capital costs will fall to $2.533 per W by 2050, a small drop from EPA's 2016 estimate, and significantly higher than prices observed in the market today. Commenters stated that in contrast to this modest projected cost decrease, solar PV system costs have consistently declined 6

- 8 percent each year from 1998 to 2013.

Commenters stated that similarly, capital costs for onshore wind energy are also overestimated in the IPM base case assumptions. Commenters stated EPA assumes costs of $2.258 per W in 2016, compared to a weighted average installed project cost of $1.63 to $1.75 per W in 2013, according to U.S. Department of Energy data. Commenters stated these current market figures are lower than EPA's projected $1.864 per W in 2050, and no cost decreases are assumed for biomass, landfill gas, or geothermal energy. Commenters stated such an approach is difficult to support given that technology learning has been shown to push down cost as the volume of technology deployed rises. Commenters stated State plans that are likely to encourage additional renewable capacity installation will continue to drive this technology learning over time.

Commenters stated the IPM base case assumptions around technology performance, which appear to be used in the modified modeling scenario without adjustment, are also inaccurate, underestimating capacit y factors and misrepresenting regional variation. Commenters recommended Building Block 3 should utilize economic modeling that more accurately reflects current technology performance and costs, and expected improvements over time. Commenters offered to pr ovide EPA with additional information to more accurately estimate technology cost and performance.

Comment 3 6 : Commenters stated that EPA's Alternative RE Approach relies on unsubstantiated assumptions about the growth and future cost of renewable technol ogies

.36 Response 3 6 : The technical potential benchmark has been eliminated in the EPA’s final methodology for building block 3. The EPA addresses considerations related to the technical feasibility and associated grid integration costs of significant RE pe netration in both the preamble (section V.E) and GHG Mitigation Measures TSD.

The following are summaries of the specific public comments under this comment:

Commenters stated that EPA's Alternative RE Approach relies on unsubstantiated assumptions about the growth and future cost of renewable technologies

. Commenters stated that EPA's A lternative RE A pproach focuses on technical potential despite acknowledging the limits of this approach. Commenters stated technical potential is divorced from reasonably a chievable RE goals because it does not consider a variety of critical factors that influence the actual deployment of RE generation. Commenters stated that despite acknowledging the concerns related to using a technical potential metric, EPA makes no effor t to address these concerns in its IPM modeling. Commenters suggested EPA's modeling should address the many other factors, aside from costs, that may limit renewable development: permitting delays (federal or tribal lands), lack of transmission, lack of f irming generation, endangered species and other environmental concerns, competing land uses, local opposition to projects, etc. Commenters stated EPA should conduct a more robust modeling analysis that factors in technology

- and region

- specific trends, pol icies and development constraints before finalizing state RE goals based on the alternate proposed approach.

Commenters stated technical potential is not synonymous with achievable renewable generation because it does not consider a variety of critical fac tors that affect actual deployment of renewable energy. Commenters stated EPA's modeling should include other factors, besides cost, that affect the deployment of renewable technologies (e.g., lack of transmission, endangered species, land use, etc.). Comm enters stated that although the avoided cost metric provides some indication of resource competition levels, it doesn't account for other associated costs stemming from the development of intermittent resources. Commenters provided the example that South D akota's 2029 renewable energy goal is more than double its entire 2012 total generation, and this example highlights an inherent flaw in considering only technical resource potential and a static fixed cost value to determine an optimal resource mix.

Comme nters stated that EPA should use a quantification methodology for renewable potential that evaluates cost

- effectiveness and uses the most up

- to

- date assumptions about expected reductions in costs of various renewable technologies to better reflect the gen uine opportunity for expanding renewable resources. Commenters additionally stated that this methodology should not apply an artificial development rate constraint.

Commenters stated EPA should use the alternative renewable energy approach, but should cond uct a more robust analysis that considers technology

- and region

- specific trends, policies and development constraints before finalizing state goals for renewable energy.37 Comment 3 7 b : Commenters developed alternative IPM runs using updated cost and capacity factor information for various renewable energy resources that show much higher levels of potential than EPA's IPM runs.

Response 3 7 : The resources and data provided in this comment were valuable in finalizing the building block 3 methodology

. The EPA has updated its cost and performance assumptions for onshore wind and solar technologies based on NREL data to reflect the most recent assessment of current data and expected future trends. The technical potential benchmark has been eliminated in the EPA’s final methodology for building block 3. The final building block 3 methodology is described in detail in V.E of the preamble and in the GHG Mitigation Measures TSD.

The following are summaries of the specific public comments under this comment:

Comme nters stated that EPA's IPM modeling assumes much higher prices for renewable generation going forward, and therefore underestimates the market potential for these technologies in the future. Commenters developed alternative IPM runs using updated cost and capacity factor information for various renewable energy resources that show much higher levels of potential than EPA's IPM runs. Commenters noted that they constructed "Updated Cost and Performance" runs of the IPM model using current levelized cost figu res for wind and solar after finding that EPA's cost figures were 46 percent higher than the current average cost. Commenters also noted that they increased the capacity factor of wind energy by 10 percent based on recent LBNL data, and reduced the capacit y value of solar photovoltaic from 20 to 16 percent. Finally, c ommenters used lower and more current figures regarding the total cost of energy efficiency programs, ranging from 4.7 to 6.4 cents per kWh, and allowed the model to select as much energy efficiency as appropriate in the economically optimized generation mix. Commen ters stated the based on these refinements, the IPM model produced a total of 469 TWh of renewable generation nationwide in 2030, compared to EPA's 278 TWh and that their model also selected 609 TWhs of energy efficiency in 2030, compared to 469 TWhs in EP A's scenario. Commenters stated that the model generated savings over a business as usual scenario of $6.4

- 9.4 billion in 2030, compared to EPA's estimated cost of $7.3 and 8.8 billion and that while the level of increased RE generation is likely affected by the higher level of EE selected by IPM under their scenarios, using updated cost and capacity factor assumptions still yielded a 60 percent increase in 2020 RE generation over EPA's case, and a 44 percent increase for 2030.

Comment 3 8 : Commenters state d building block 3 should address transmission costs.

Response 3 8 : The EPA addresses considerations related to the technical feasibility and associated grid integration costs of significant RE penetration in both the preamble (section V.E) and GHG Mitigat ion Measures TSD.

The following are summaries of the specific public comments under this comment:

Commenters stated if EPA finalizes the Alternative RE Approach, it should ensure that final assessment of building block 3 consider transmission costs and no ted that significant additions of38 renewable energy could require either additions of more transmission capacity, different configurations of transmission facilities, or both.

Commenters noted that many of the prime areas for renewable development are locat ed far from load centers and will require new transmission to be built to deliver the power to load centers. Commenters stated that NERC noted that EPA's analysis assumes that adequate transmission capacity is available to deliver any resources located in, or transferred to, the region, but that given the significant changes and locations anticipated to occur in the resource mix, it is likely that additional new transmission, or transmission enhancements, will be necessary and required to transport the amou nt of renewable generation coming online, particularly in remote areas. Commenters noted that a typical transmission line requires five years or more to site, permit and construct and that large

- scale transmission projects, such as high

- voltage overlays and those needed for renewable integration can involve even longer lead times. Commen ters added that given the likely changes in the operational status of many existing fossil units, many studies may need to be done to identify where new and upgraded transmission will be needed.

Commenters stated that with current RE generation of approxim ately 10,000 GWh and Minnesota's current renewable energy standard (RES) requirements for future years, EPA's alternative RE goal is not an unreasonable projection of renewable potential for Minnesota, if production tax incentives for renewable energy rema in in place, economic growth continues, and the cost of renewable energy continues to decline relative to the cost of other resources. Commenters stated Minnesota ratepayers have already made significant transmission investments to enable Minnesota utiliti es to reach the state's RES requirements. Commenters stated for the State to be able to reach the alternative RE target level of RE generation, an evaluation of additional transmission investment may be needed.

Comment 3 9 : Commenters urged that that capit al cost adders implemented in EPA's analysis be updated to reflect real

- world conditions in the solar PV and wind industries

. Response 3 9 : The resources and data provided in this comment were valuable in finalizing the building block 3 methodology

. The EPA updated its short

- term capital cost adder framework to reflect updated capital cost assumptions and historical deployment levels

. Refer to the IPM documentation available at http://www.epa.gov/airmarkets/powersectormodeling.html www.epa.gov/powersectorm odeling for additional detail. For the EPA’s response to this comment, see section V.E of the final rule preamble of the CPP and chapter 4 of the GHG Mitigation Measures TSD for CPP Final Rule.

The following are summaries of the specific public comments under this comment:

Commenters urged that capital cost adders implemented in EPA's analysis be updated to reflect real

- world conditions in the solar PV and wind industries. Commenters stated that the upper bounds for renewable energy in EPA's Alternative R E Approach are extremely restrictive because they are well below the growth potential already widely

- demonstrated by the wind and solar industries. Commenters provided the following example: "the step 1 upper bound over the 2016

- 2018 model period is 11.6 G W for onshore wind; in reality, the capacity

- weighted average39 capital cost of wind projects installed in the U.S. dropped by 10 percent in 2012, despite installing a record 13.1 GW that year, and a combined 19.7 GW over the 2011

- 2012 period. Additionally, commenters said the step 1 upper bound for solar PV is only 0.3 GW, but utility

scale installations were nearly 10x that amount in 2013, reaching 2.9 GW. Commenters requested that these capital cost adders be updated to better reflect real

- world conditions and the recent sustained growth in the solar PV and onshore wind industry.

Commenters stated that while the logic underpinning the cost adder process is sound, it is likely overstated. Commenters noted that EPA's 2016 threshold for wind is likely low, given that the wind industry installed 12.7 GW of onshore wind in 2012 at prices lower than the prior year, suggesting that scarce labor and materials were not encountered. Commenters noted , however, that the thresholds in 2018 and going forward appear reasonable, and thus this may not be a significant concern for the onshore wind modeling. Commenters stated that in the case of solar PV, the threshold is set very low, and the cost adder is quite high. Commenters said t his inappropriate data will limit the market potential of solar PV in the IPM runs. Commenters stated that there is insufficient evidence to support a volume threshold in 2016 for a short

- term cost adder that is approximately 10% of the vo lume installed 3 years prior and that there is also insufficient evidence that the cost adder should be 33% of the installed cost. Commenters noted that the actual industry capacity far outpaces this volume, making it inappropriate and stated therefore tha t EPA should increase the threshold to a figure that is larger than past installations and that appropriately allows for industry expansions as a response to demand signals and adjust the cost adder down to reflect the relative ease and low cost of expandi ng the solar PV industry capacity.

Commenters requested that EPA drop or modify the short

- term capital cost adders that raise the cost of renewables by an unreasonabl e amount. Commenters stated that the EPA also applied unrealistically high short

- term capi tal cost adders to renewable and conventional generation technologies if the new capacity developed in a specific year exceeds a certain uppe r bound

. Commenters believed that the assumptions made by the EPA are not supported by actual experience or credibl e peer

- reviewed research.

Comment 40 : Commenters stated that EPA has not provided justification for applying a singular assumed cost reduction of $30/MWh across the country.

Response 40 : The reduced cost of $28/MWh is a cost

- effectiveness determination made by EPA and does not represent an expectation of future cost decline or market conditions

. Each of the building blocks establishes a cost

- effectiveness threshold against which emission reduction opportunities are weighed

. For building blocks 2 and 3 th at determination is $40/ton

. This $/ton cost is then translated into a $/MWh capital cost reduction for BSER RE technologies assuming that incremental RE replaces affected source generation at an average emissions intensity of 0.7 ton/MWh

. An emissions int ensity of 0.7 tons/MWh is consistent both with the historical emissions intensity of the affected source fleet in 2012 as well as IPM base case projections of affected source performance

. The cost reduction assigned to all BSER RE technologies impacts the capital cost of the RE build options; the variable cost of dispatch is unchanged

. The $40/ton
cost

- effectiveness level is consistent for all areas of the country to promote geographical equity;40 emission reduction opportunities are evaluated based on cost, not location. The EPA addresses considerations related to the technical feasibility and associated grid integration costs of significant RE penetration in both the preamble (section V.E) and GHG Mitigation Measures TSD.

The following are summaries of the s pecific public comments under this comment:

Commenters stated that EPA has not provided any analysis or justification for applying a singular assumed cost reduction of $30/MWh across the country within its IPM modeling since changes in cost are typically i ndependent of other renewable technologies and can vary by region.

Commenters stated that EPA's use of a single number applied across the country is a misapplication of the concept of avoided cost. Commenters stated that if EPA must pursue this approach, i t should consider instead using the IPM model with an imposed CO2 constraint, then let the model meet the constraint at the lowest cost without changing the cost assumptions for RE technologies used in the model. Commenters noted that the model output woul d presumably include some amount of RE for the region, which could then be apportioned between the states based on an examination of each state's relative endowment of economic RE resources. Commenters noted that is this is unacceptable, EPA could apply a CO2 price slightly less than the Social Costs of Carbon of $13/ton in 2020, increasing to $17 by 2030 to ensure cost do not exceed benefits and then use the IPM output to set the RE building block target.

Commenters stated that EPA provides no evidence or substantiation for its assumption that renewable technologies, as a whole, will continue to decline in cost at the magnitude of $30/MWh, nor does EPA provide a baseline number from which $30/MWh is deducted. Commenters noted that applying a $30/MWh cost re duction to the current prices for wind could result in a value below zero in some regions of the country which is neither credible nor reasonable. Commenters also noted that DOE's latest Utility

- Scale Solar 2013 report notes that "with PPA prices [for sola r] now hovering around $50/MWh on average (based on the combined 2013/2014 sample), future price declines are likely to be much smaller than in the past". Commenters moreover stated that the cost of RE technologies remains heavily influenced by public poli cies and noted that the cost reduction due to subsidies varies by technology, but can be as much as $42/MWh on a levelized basis. Commenters stated that if EPA finalizes its alternate proposed approach, it must provide sufficient data and analysis to justi fy this number and if no such analysis is available, then EPA must remove the estimate altogether from any calculation of state RE targets and should not adjust IPM results by any estimated cost decline.

Commenters stated that EPA's attempt to apply renewa ble energy goals that must be achieved by all states based on limited, region

- specific data is flawed and instead, EPA should use state, regional, and technology

- specific costs in its modeling approach as opposed to a broad average that is assumed to be ac hievable by all renewable energy resources, regardless of location and/or the continued availability of federal subsidies for certain renewables. Commenters further stated EPA provided no evidence regarding if, when, or how its assumption that renewable en ergy technologies, as a whole or individually, would be reduced by $30/MWh could be achieved, nor does the agency provide any details regarding the baseline cost from which the $30/MWh rate was reduced. Commenters noted that although the cost of renewable resources is strongly41 influenced by tax credits and subsidies, federal production tax credit and investment tax credit have already expired or are scheduled to expire before the states file compliance plans. Commenters stated that it is not reasonable to e xpect costs to continue to decline at the same level as experienced in recent years when these tax benefits were available. Commenters urged EPA to provide sufficient data and analysis to justify this number if EPA is to finalize the Alternat iv e RE Approach and that if no such analysis is available, requested that EPA remove the estimate from any calculation of state RE targets altogether.

Commenters noted that even though EPA indicated that this cost reduction "represent[s] the avoided cost of other actions that could be taken instead to reduce power sector CO2, and [intended] to reflect continued reductions in RE technology costs", and that the $30/MWh cost reduction is "consistent with the estimated cost of the proposed approach (up to $40 per metr ic ton of CO2)", a $30/MWh cost reduction for renewables would be equivalent to much higher implied CO2 prices (about $70/ton in a market with natural gas on the margin). Commenters stated that EPA appeared to imply that imposing a cost reduction for renew ables of $30/MWh is equivalent to adding a future cost of $30/MWh to the market price of electricity, similar to a CO2 allowance price. Commenters tested the reasonableness of EPA's statement by calculating the CO2 allowance price associated with a $30/MWh cost adder to compare with EPA's $40/ton
cost. A ssuming natural gas units set the market price, the commenters assumed an average heat rate for natural gas units of 8,000 Btu/KWh, and a CO2 content of natural gas of 117 lb/MMBtu and found that the $30/MWh additional cost equates to a CO2 allowance price of $70/ton ($30 MWh / (8 MMBtu/MWh x 117 lb/MMBtu / 2,200 lb/ton) = $70/ton), which is much higher than EPA's $40/ton cost.

Commenters noted that the $10 to $40 metric is derived from an "an EPA analysis b ased on EIA levelized costs..." Commenters stated this analysis is not available in the docket, and the levelized cost EPA cites does not otherwise support EPA's position. Second, the commenters stated, even if the $10 to $40 metric were reasonable, EPA ha s provided no rationale for how the $30/MWh cost reduction selection is consistent with this range or, if it was, why $30/MWh was chosen as opposed to another value within the range. C ommenters stated EPA must provide an adequate justification for its usag e of the $30/MWh cost reduction. Commenters stated that the $30/MWh limitation is not sufficient to offset EPA's overestimation of state renewable potential based on flaws in the NREL data.

Commenters also stated since subsidies such as the investment tax credit (ITC) and the production tax credit (PTC) have expired or are scheduled to expire before compliance begins, it is unreasonable to assume that renewable technology costs will continue to decline at the same level as experienced under the tax credits.

Commenters stated that a single reduction estimate is not appropriate for estimating the future costs of all renewable technologies as each technology changes in cost at its own rate.

Comment 41 : Commenters suggested the EPA replace the generic $30/MWh cost reduction threshold that is applied nationwide with cost effectiveness criteria that more closely tracks regional avoided cost data, or that scales up over time

.42 Response 41 : The reduced cost of $28/MWh is a cost

- effectiveness determination made by EPA and does not represent an expectation of future cost decline or market conditions. The $40/ton
cost

- effectiveness level is consistent for all areas of the country to promote geographical equity; emission reduction opportunities are evaluated based on c ost, not location

. IPM projections of economic potential under a reduced cost reflect regional opportunities, constraints, and market conditions. The EPA addresses considerations related to the technical feasibility and associated grid integration costs of significant RE penetration in both the preamble (section V.E) and GHG Mitigation Measures TSD

. The following are summaries of the specific public comments under this comment:

Commenters suggested to replace the generic $30/MWh cost reduction threshold th at is applied nationwide with cost effectiveness criteria that more closely tracks regional avoided cost data, or that scales up over time. Commenters stated in the manner that EPA envisions in section 1.4 of the Alternative RE Approach TSD, or based on a simpler approach, EPA should develop a regional cost curve (or curves) so that the cost effectiveness threshold can be determined based on the avoided costs of energy in the region. Commenters stated if regional or state specific data can't be generated fo r any given state the EPA could revert to a generic nationwide figure along the lines of what was already modeled for the proposal. Commenters stated if EPA is unable to do more specific regional modeling, and chooses to retain its cost effectiveness thres hold starting at $30/MWh, it may make sense to increase it to $50/MWh or a similar level by 2030 to encourage penetration of alternative technologies. Commenters stated precise trajectory would need to be modeled, and could vary by state or region, but the essential concept is that more renewable energy should be encouraged over time.

Comment 4 2 : Commenters stated that the EPA should consider using the IPM with an imposed CO2 constraint, then let the model meet the constraint at the lowest cost

. Response 4 2 : The reduced cost of $28/MWh is a cost

- effectiveness determination made by EPA and does not represent an expectation of future cost decline or market conditions

. Each of the building blocks establishes a cost

- effectiveness threshold against which emissi on reduction opportunities are weighed

. For building blocks 2 and 3 that determination is $40/ton

. This $/ton cost is then translated into a $/MWh capital cost reduction for BSER RE technologies assuming that incremental RE replaces affected source generat ion at an average emissions intensity of 0.7 ton/MWh

. An emissions intensity of 0.7 tons/MWh is consistent both with the historical emissions intensity of the affected source fleet in 2012 as well as IPM base case projections of affected source performance

. The cost reduction assigned to all BSER RE technologies impacts the capital cost of the RE build options; the variable cost of dispatch is unchanged

. The $40/ton
cost

- effectiveness level is consistent for all areas of the country to promote geographical equity; emission reduction opportunities are evaluated based on cost, not location. IPM projections of economic potential under a reduced cost reflect regional opportunities, constraints, and market conditions. The EPA addresses considerations related to t he technical feasibility and associated grid integration costs of significant RE penetration in both the preamble (section V.E) and GHG Mitigation Measures TSD.43 The following are summaries of the specific public comments under this comment:

Commenters stated that EPA's solution to acknowledge the limits of technical potential of arbitrarily reducing the cost of RE input assumptions by $30/MWh used in the IPM is suspect and instead, EPA should consider using the IPM with an imposed CO2 constraint, then l et the model meet the constraint at the lowest co st

. Commenters stated that this would presumably include some amount of RE for the region, which could then be apportioned between the states based on an examination of each state's relative endowment of RE resources. Commenters stated that if this is unacceptable, EPA could apply a CO2 price slightly less than the social costs of carbon to ensure net benefits are not exceeded and use the IPM output to set the RE building block target. Commenters cited EPA's 2010 analysis of the American Power Act in the 111th Congress to note that EPA's previous modeling of CO2 reduction proposals has shown that RE is not the least cost means to lower CO2 emissions.

Comment 4 3 : Commenters completed separate analyses of EPA's RE Market Potential scenario, and noted that EPA's use of a $30/MWh reduction metric is reasonable.

Response 4 3 : The resources and data provided in this comment were valuable in finalizing the building block 3 methodology

. The EPA continues to rely on a cost

- effectiveness determination of $40/ton for building block 3

. For the EPA’s response to this comment, see section V.E of the final rule preamble of the CPP and chapter 4 of the GHG Mitigation Measures TSD for CPP Final Rule.

The following are summaries of the specific public comments under this comment:

Commenters completed separate analyses of EPA's RE Market Potential scenario, in which a $30/MWh cost reduction is applied to onshore wind and solar PV, and noted that EPA's use of a $30/MWh reduction me tric is reasonable. Commenters updated capital costs and performance for onshore wind and utility

- scale solar PV, included conservative assumptions about solar cost declines, and also updated the capital cost adders to reflect recent industry growth. Comme nters constrained variable renewable generation at 30% of generation based on the results of several studies, which the c ommenters expected to be revised upwards by EPA as a result of EPA examining the latest available research. Commenters modeled two scen arios

- one with and one without deployment of distributed solar PV. Commenters noted that in the run with distributed solar PV incorporated into IPM, capacity installations by state are developed using DOE/NREL Sunshot projections under the

- 62.5% price s cenario, and in their case, distributed solar was also updated based on the most recent Sunshot update

- which assumed that solar prices would reach the

- 62.5% reduction by 2020 and the full

- 75% reduction by 2030. Commenters also noted that they attempted to match EPA's modeling exercise as closely as possible and outlined their approach accordingly. Commenters claimed that their results demonstrate that renewable energy generation can reach 873 TWh from utility

- scale plants, and can reach 973 TWh when dis tributed solar is accounted for

- between 65% and 86% higher than both of EPA's target

setting approaches. Commenters also stated that the $30/MWh cost reduction lead to an average cost of CO2 abatement of only $14/tonne in 2020, rising slightly to ~$19/to nne in 2030.44 Commenters updated the cost assumptions for solar and wind energy that are used in the IPM model and stated that their results of $14/metric ton avoided carbon emissions in 2020 and $19/metric ton avoided carbon emissions in 2030 fell well wit hin the range of $10

- $40/metric ton of avoided carbon emissions that the EPA had initially set. Commenters further stated that these model results also demonstrate that renewables, including solar, are a reasonable cost emissions reduction measure.

Commen t 4 4 : Commenters cited issues with the NREL data used by EPA to calculate resource potentials under the Alternat iv e RE Approach.

Response 4 4 : The resources and data provided in this comment were valuable in finalizing the building block 3 methodology. Due to c ommenters concerns, the technical potential benchmark has been eliminated in the EPA’s final methodology. The EPA addresses consideration s related to the technical feasibility and associated grid integration costs of significant RE penetration in both the preamble (section V.E) and GHG Mitigation Measures TSD.

The following are summaries of the specific public comments under this comment:

Commenters cited issues with the NREL data used by EPA to calculate resource potentials under the Alternative RE Approach. Commenters recommended that EPA not adopt the Alternative RE Approach, as they felt that the NREL data used by EPA to reach its concl usions overestimated various resource potentials. Commenters noted that NREL's methodology is based on a power density of 32.9 MW and 48 MW per square kilometer for concentrating solar power (CSP) and utility scale single axis solar PV, respectively . H owev er, commenters stated NREL's more recent report on actual solar power densities of utility scale projects in the United States

, indicate that actual solar power densities are 20

- 38 percent lower than the NREL potential study used to inform EPA's proposed a lternative. C ommenters also noted that the NREL study EPA used overestimates available land area, which is based on NREL Geographic Information Systems exclusion criteria. Commenters noted that the exclusionary zones used by NREL appear to focus primarily on federal lands such as federal parks, federal wilderness, national conservation areas and the like and that the study does not address various additional constraints to renewable energy development that exist across the states. Commenters noted that the Western U.S. contains a high percentage of federal lands and that any new generation or transmission projects constructed within these lands, including renewable resources, have a high probability of triggering the National Environmental Policy Act (NEPA) process directly or through a connected action. Commenters noted that once NEPA is triggered during the development phase of a new project, it can take multiple years to complete the process before construction begins. Lastly, c ommenters noted that many of the renewable development areas identified by the NREL study contain sensitive plant and animal species, such as the Greater Sage Grouse, and some contain acreages designated as Area(s) of Critical Environmental Concern.

Commenters noted that while the NR EL study specifically listed certain areas that were excluded from consideration, there were several important categories that were not properly excluded; with regard to onshore and offshore wind, for example, the study does not consider the military

use o f areas outside of Department of Defense installations, such as military air navigation45 routes, air traffic control areas, military training routes, special

- use air space, radar, and other potentially affected military operations. Commenters noted that Nor th Carolina is home
to numerous national wildlife refuges that are important habitats for migratory birds and while NREL's analysis excluded the wildlife refuges themselves, the study did not appear to fully consider the appropriateness of limitations on w ind development in migratory bird flyways or other important habitats used by migratory species. Commenters felt that EPA's generation goals are overstated by not factoring in some of these additional limitations on each state's RE technical potential and other state

- specific circumstances. Commenters stated that the North Carolina Energy Policy Council contracted with La Capra Associates to develop a technical potential study in 2011 of the amount of renewable energy that was technically and practically

ac hievable in North Carolina and that the La Capra study found that North Carolina has the technical potential in State waters of 1.96 GW and 37.2 GW in federal waters for a total North Carolina technical potential of over 39 GW, but found that the practical potential was about a third of that (579 MW in State waters and 13.3 GW in federal waters for a total of 13.9 GW). Commenters noted by comparison that the NREL report found that North Carolina had a technical potential of 306 GW. Commenters stated that while they do not endorse the findings of the La Capra Report, it provides an example how a state

- specific study can provide significantly different results from studies that look at the entire nation or a region. Commenters also noted that in the three years since the study was completed, the development of renewable energy in North Carolina has proceeded much differently than what the La Capra study anticipated, highlighting how quickly factors in each state can change.

Commenters stated that the environmental exclusions NREL relied upon underestimate restrictions to RE deployment and, as a result, NREL significantly overestimated state RE potential. Commenters noted that the most recent exclusion data NREL relied upon is five years old, while the majority is roughly a decade old with some data roughly two decades old. Commenters stated that NREL failed to consider exclusions for the more than 2.6 million acres recently designated as National Conservation Areas, National Monuments, Wilderness Ar eas, and National Parks and also did not consider state and local land use constraints that were adopted in the last ten years in determining wind or hydropower potential, and NREL did not consider any state or local land use restrictions in determining t he potential for other RE technologies. Commenters also noted that none of the exclusion data sets that NREL utilized are necessarily based on the habitats of species listed under the Endangered Species Act. Commenters stated that NREL failed to consider e xclusions for the habitats of roughly 740 threatened and endangered animal species. Commenters also noted that the NREL report does not provide an accurate representation of hydropower potential since NREL based its estimates on a decade

- old study that in turn relies on even older median data. Commenters further noted that the NREL report does not consider the following factors: construction costs, the cost of necessary supportive infrastructure, the availability of existing or planned transmission, reliabi lity, or current or future electricity loads. Commenters stated that EPA cannot say that these factors are accounted for by applying benchmark rates because the benchmark determination is seriously flawed, and even if the benchmark analysis accurate, it is inappropriate to say that a national benchmark average takes into account these state

- specific factors.

Commenters noted that for onshore wind, NREL includes wind resource at 80 meters that results in an annual average gross capacity factor of 30% using typical utility

- scale wind turbine power46 curves which EPA utilizes in its Alternative RE Approach, but that 100 meter wind data are readily available through NREL. Commenters noted that NREL released a new map of wind resources to keep pace with wind techn ology, specifically citing 100 meter towers on July 30, 2014. Commenters also noted that taller towers are commercially available and in fact already utilized at a number of wind farms in the United States. Commenters stated that at the end of 2011 approxi mately 400 turbines in the US had towers taller than 80 meters and since then over 2000 wind turbines have been installed with towers taller than 80 meters. Commenters noted that according to NREL, 15% of wind turbines installed in 2012 had hub heights of 100 meters or higher. Commenters also noted that the power curve of typical wind turbines has evolved significantly in the past couple of years as rotor diameter, advanced controls and other technological developments have occurred. While c ommenters stated that the technical potential for solar PV seems to be fairly accurate, they did not agree with EPA's assumption that wind and solar PV performance will become static over time and stated contrastly that the performance of these technologies is expected to continue to improve at a meaningful pace.

Commenters recommended that EPA further refine the Alternative RE Approach, if EPA chooses to pursue it, by using a more robust selection of reference resources rather than just using the single NREL study of tech nical potential, making it more representative by applying to all states rather than just the top one one

- third of (16) states in defining the average development rate; and providing a more complete and documented review of the cost reduction target modeli ng of future market potential.

Commenters noted that the NREL report only considered technical feasibility and did not consider factors such as: economics; availability of existing or planned transmission infrastructure; relative reliability or time

- of

- pro duction of power; local, state, regional, or national polices; or the location or magnitude of current and potential electricity loads. Commenters noted that these factors are critical to evaluate a state's true potential for development of renewable energ y.

Comment 4 5 : Commenters expressed concerns related to using a technical potential metric

. Response 4 5 : The resources and data provided in this comment were valuable in finalizing the building block 3 methodology. Due to c ommenters concerns, the technical potential benchmark has been eliminated in the EPA’s final methodology. The EPA updated cost and performance assumptions for onshore wind and solar technologies in the final methodology

. The EPA addresses considerations related to the technical f easibility and associated grid integration costs of significant RE penetration in both the preamble (section V.E) and GHG Mitigation Measures TSD.

The following are summaries of the specific public comments under this comment:

Commenters stated that despit e acknowledging the concerns related to using a technical potential metric, EPA does not address these concerns in its modeling. Commenters stated that EPA's modeling should address the many other factors, aside from costs, that may limit renewable develop ment: lack of transmission, endangered species and other environmental concerns,47 competing land uses, public opposition, etc. Commenters stated that EPA should conduct a more robust modeling analysis that factors in technology

- and region

- specific trends, policies and development constraints before finalizing state RE goals based on the alternate proposed approach.

Commenters states that the EPA should re

- run the IPM modeling using updated assumptions for renewable technologies and consider different model ing approaches from other sources that use similar assumptions. Commenters support ed the National Resource Defense Council's analysis of the EP A's A lternative RE A pproach using an updated version of the IPM model, and stated this addresses many of their co ncerns. Commenters noted that EPA's IPM modeling of meeting
state emission rate reduction targets completed for the regulatory impact analysis resulted in a much lower level of renewables than either their Proposed Approach or Alternative RE A pproach. Commenters believed that these results imply that the Clean Power Plan would result in less renewable generation than expected under existing state and federal policies without the CPP. Commenters felt that the current model is "pessimistic" regarding rene wable potential and that it does not capture the economic potential for deploying renewables at higher levels to cost

effectively achieve deeper emission reductions

.

Comment 4 6 : Commenters had concerns about how hydroelectric generation was calculated in the Alternative RE Approach.

Response 4 6 : The final building block 3 target generation level applies to incremental RE only, including hydropower

. The amount of incremental hydropower included in building block 3 is a function of historical changes in ca pacity

. Target generation levels are then validated in terms of technical feasibility and cost

- effectiveness through IPM modeling projections, in which EPA has included new hydropower build options based on the latest cost and performance information from DOE

. For the EPA’s response to this comment, see section V.E of the final rule preamble of the CPP. Refer to the GHG Mitigation Measures TSD for further detail on how incremental hydropower was quantified as part of building block 3.

The following are summaries of the specific public comments under this comment:

Commenters had concerns about how hydroelectric generation was calculated in the Alternative RE Approach. Commenters stated generation from hydroelectric power is nominally included in the Alter native RE Approach; however, the methodology used to calculate hydroelectric generation is problematic and will result in an underestimation of new hydroelectric resources. Commenters stated because "the study that formed the basis of NREL's hydropower tec hnical potential estimate applied a full set of feasibility criteria to the development opportunities for new low power and small hydroelectric plants," the Alternative RE Approach calculates benchmark generation for hydropower using the technical potentia l identified for each state without adjusting it by a benchmark development rate. Commenters stated that importantly, the study cited by EPA is an estimate only of potential new hydroelectric generation and does not include generation from existing hydroel ectric dams. Commenters then stated however, EPA then takes the "greater of each state's reported 2012 conventional hydroelectric generation, or the feasible hydropower development potential identified by NREL." Commenters stated this makes48 little sense, a s there is no reason a state should be held to either potential new hydroelectric generation or existing generation. Rather, c ommenters suggested these values should be added together to get an estimate of total potential hydroelectric generation. Or, c omm enters stated, if EPA plans to exclude existing conventional hydroelectric generation from BSER as it proposes to do under the Best Practices Approach, it should use the values estimating achievable levels of new hydroelectric generation from the NREL repo rt for each state without subtracting out the MWh from existing hydropower facilities in 2012.

Commenters also stated that the calculation of hydroelectric generation under the IPM projection also requires adjustment. Commenters cited EPA that "IPM is not currently configured to project the economic deployment of new hydropower resources in the United States." Commenters noted however, rather than therefore relying only on the benchmark generation estimate, the Alternative RE Approach uses IPM projections of generation from existing hydropower facilities in 2020, 2025, and 2030. Commenters stated this approach has two problems. Commenters stated that first, because the Alternative RE Approach uses the lower of benchmark generation (which includes only new h ydropower) and IPM projected generation (which includes only existing hydropower), this effectively ignores any new hydroelectric construction estimated by the NREL report. Commenters stated that second, the inclusion of generation from existing hydroelect ric facilities in the IPM calculation but exclusion of existing hydropower in the benchmark approach creates an unexplained inconsistency. Commenters stated given the full suite of feasibility criteria used in the study underlying the NREL report used to s et benchmark hydroelectric generation, if EPA decides to finalize the Clean Power Plan's BSER calculation without including existing hydroelectric generation, EPA should use only the technical potential estimate for new hydroelectric generation in each sta te from the NREL report as the basis for calculating each state's technically feasible, cost effective generation from hydropower. Alternatively, c ommenters stated, if EPA decides to include generation from existing hydroelectric facilities, it should incl ude existing hydroelectric generation both in its calculation of generation using IPM, as proposed, and in its calculation of benchmark hydroelectric generation. However, c ommenters stated, generation from existing hydroelectric facilities should be includ ed separately from new hydroelectric generation so that the limits of the IPM model do not lead to the false assumption that no new hydroelectric generation is feasible.

Commenters stated that the NREL report referenced by EPA does not provide accurate estimates on which hydroelectric power target generation, rather, when c ommenters compared DOE's estimated potential capacity for four of the potential sites in Alabama with the actual capacity requested in preliminary permits filed with FERC, DOE's estimates grossly overstated potential capacity. Commenters also pointed out that the reports used to quantify hydroelectric power potential contain outdated information. For instance, c omme nters noted that one of the sites identified in the DOE's report, "An Assessment of Energy Potential at Non

- Powered Dams in the United States," (April 2012) as a top 100 non

- powered dam

-- the Eagle and Phoenix Mill site on the Chattahoochee River in Georgia

-- no longer exists and that two other sites identified as top 100 non

- powered dams have experienced downward

- trending flows over the last 30 years. Commenters also noted that average flows identified in the April 2012 report for the Demopolis Lock and Dam and the George Andrews Lock and Dam likely overestimate the potential hydroelectric power generation at these sites. Commenters stated that the expansion of critical habitat areas in Alabama and Georgia under the Endangered Species Act may have affected hy droelectric potential in these states, which is not considered in any reports cited by EPA.49 Comment 4 7 : Commenters expressed concern about the interaction between EPA's Alternative RE Approach under Building Block 3 and the remaining Building Blocks

. Response 4 7 : The final procedure for building block 3 is consistent with procedure adopted for each the other building blocks

. If the technical potential of a building block exceeds the EPA’s
cost

- effectiveness determination, then it is appropriate to prem ise the building block stringency on economic potential

. For building block 3, the technical potential for incremental RE is significant

. For example, a 2012 NREL study explored high

- penetration renewable electricity futures of up to 90% of total U.S. elec tricity generation. 1 The basis for building block 3 target generation levels is the observed pattern of historical development for each of the BSER RE technologies

. Modeling projections serve an important role in validating the technical feasibility and co st

- effectiveness of the target generation level

. This procedure

– observing historical performance, applying that performance to future years, and validating the results through modeling projection

– is consistent across building blocks 2 and 3

. For additi onal detail on the BSER, refer to section V of the preamble.

The following are summaries of the specific public comments under this comment:

Commenters stated concern about the interaction between EPA's Alternative RE Approach under Building Block 3 and the remaining Building Blocks. Commenters noted that in the majority of states, EPA's A lternative RE A pproach used the carbon price metric rath er than the technical potential to set the Building Block 3 requirement

. Commenters stated that nowhere else in the Building Block structure of the Proposed Rule does EPA differentiate a state's emission reduction requirements based on a carbon price. Comm enters provided the example that for Building Block 2, it is required that a 70% capacity factor be applied for NGCCs in every state regardless of what carbon price may be implied by that requirement. Commenters stated that EPA should not arbitrarily apply a carbon price in Building Block 3 while holding the state requirements in the other building blocks constant regardless of their cost implications. Commenters also noted that in other states, the targets were set by theoretical potential and not limited by the economic modeling step which makes EPA's approach arbitrary in these states because it is based on natural resource availability, which differs from the approaches of the other Building Blocks.

Commenters stated the EPA appears to acknowledge the im portance of incorporating renewable energy generation based on the actual potential for each state, and the approach described in the technical support documentation "Alternat ive Renewable Energy Approach" may be closer to representing state realities as i t relies in part on a technical potential study conducted by NREL. Commenters stated this approach, however, falls short due to the use of EPA's Integrated Planning Model (IPM) to evaluate market potential of each type of renewable generation based

on a re gional dispatch area and the use of an estimated incremental cost of renewables. Commenters stated that EPA did not provide information regarding the impact on the A lternative

1 http://www.nrel.gov/docs/fy12osti/52409

- 1.pdf50 RE A pproach to the emission performance requirements for Florida, specifical ly w hether the adoption of the A lternative RE A pproach would affect the other Building Blocks.

Comment 4 8 : Commenters stated the alternative RE proposal would have a significant impact on Minnesota's final target

. Response 4 8 : The final building block 3 methodology does not rely on state

- specific deployment estimates, but rather cost

- effective RE at an interconnection level

. The basis for building block 3 target generation levels is the observed pattern of historical development for each of the BSER RE te chnologies

. Modeling projections remain an important aspect of the overall methodology in validating the technical feasibility and cost

- effectiveness of the target generation level

. The EPA addresses considerations related to the technical feasibility and associated grid integration costs of significant RE penetration in both the preamble (section V.E) and GHG Mitigation Measures TSD.

The following are summaries of the specific public comments under this comment:

Commenters stated the alternative RE proposal would have a significant impact on Minnesota's final target without reasonable adjustments. Commenters stated Minnesota, already a clean energy leader in the U.S., would be expected to reduce the carbon intensity from its base year emissions by more than half, and do so within little more than a decade. Commenters stated that a 2030 final reduction goal of 700 lb/MWhr resulting from the alternative RE proposal could be problematic, noting that this is the CO2 emissions rat e achievable by a new NGCC, but little else.

Comment 4 9 : Commenters disagreed with EPA's Alternative RE Approach in which EPA indicated that that non

- hydro RE generation in Indiana can reach 21,951 gigawatt hours (GWh) by 2029

. Response 4 9 : The final building block 3 methodology does not rely on state

- specific deployment estimates, but rather cost

- effective RE at an interconnection level

. The basis for building block 3 target generation levels is the observed pattern of historical development for each of the BSER RE technologies

. Modeling projections remain an important aspect of the overall methodology in validating the technical feasibility and cost

- effectiveness of the target generation level

. The EPA addresses considerations related to the technical feasibility and associated grid integration costs of significant RE penetration in both the preamble (section V.E) and GHG Mitigation Measures TSD.

The following are summaries of the specific public comments under this comment:

Commenters fundamentally di sagreed with EPA's Alternative RE Approach in which EPA indicated that that non

- hydro RE generation in Indiana can reach 21,951 gigawatt hours (GWh) by 2029. Commenters noted that this is a 519 percent increase in RE generation compared to Indiana's demons trated performance of 3,546 GWh in 2012. Commenters stated that while51 Indiana achieved high RE generation growth rates from 2007 to 2011, RE generation in 2012 was 2.06 percent lower than RE generation in 2011 and that it is unrealistic for EPA to assume
t hat Indiana can achieve consistently high levels of RE generation growth, especially considering that increases in RE capacity were significantly driven by the federal government's Production Tax Credit (PTC), which expired at the end of 2013. Commenters a dditionally noted that data from EIA show that capital costs associated with renewable energy deployment are generally much greater than capital costs associated with natural gas combined cycle deployment, making this approach much more costly to Indiana c onsumers than necessary.

Comment 50 : Commenters provided a list of questions abo ut the Alternative RE Approach covering several topics.

Response 50 : The final building block 3 methodology does not rely on state

- specific deployment estimates, but rather cost

- effective RE at an interconnection level

. The basis for building block 3 target generation levels is the observed pattern of historical development for each of the BSER RE technologies

. Modeling projections remain an important aspect of the overall me thodology in validating the technical feasibility and cost

- effectiveness of the target generation level

. The EPA addresses considerations related to the technical feasibility and associated grid integration costs of significant RE penetration in both the p reamble (section V.E) and GHG Mitigation Measures TSD.

The following are summaries of the specific public comments under this comment:

Commenters provided a list of questions about the Alternative RE Approach:

1. Does the EPA intend to pursue the Alternative Renewable Energy Approach for calculating state RE targets? How will that decision be made?

2. The GIS

- based approach would tie each state's RE goal to the "average development rate of the top third (16) of states." What is EPA's technical basis for assuming that all states can deploy their potential RE resources to the same extent as the top 16 states?

3. The IPM

- based approach would model reduced costs for developing new RE sources based on "the avoided cost of other actions that could be taken instead to redu ce power sector CO 2 ." What does this mean? How would this approach accurately estimate a state's potential for cost

- effective RE generation?

4. Please detail the peer

- review each study underwent.

5. Why was bio

- mass and landfill RE excluded?

6. What modeling "reduced costs"? Was this based on the PTC? LOCE?

7. Geothermal

- why were the top 5, and not top 16 states considered in this portion?

8. What changed in the methodology? Why did the EPA not consider non

- air impacts?52 9. The EPA explains that because NREL used "feasibility criteria" there is a totally different process for analysis. However, the study cited does not even look at economics.

10. What was the technical basis for this radically different approach?

11. What was the technical basis for the EPA's analysis for Alaska and Hawaii?

12. Why did the EPA not apply the limiting methodology used in BB2?

Comment 51 : Commenters expressed concern that targets come from averaging regional RPS program targets within the region.

Response 51 : The final building block 3 methodolog y does not rely on state RPS requirements to establish regional targets , but rather cost

- effective RE at an interconnection level

. The final methodology is described in section V.E of the preamble and in the GHG Mitigation Measures TSD

. The following are summaries of the specific public comments under this comment:

Commenters had a question regarding the Regional RE Generation targets, in particular the target for the South Central region. Commenters noted that the GHG Abatement TSD on page 4

- 17 states tha t the South Central region has a 20% RE Generation Target and that EPA also mentions that these targets come from averaging regional RPS program targets within the region. Commenters noted that only Kansas and Texas have RPS programs within the South Centr al region, however both are capacity

- based. Commenters stated that according to the GHG Abatement TSD, EPA excluded the capacity

- based programs from the averaging. Commenters wanted to know whether the South central region 20% RE generation target comes fr om Kansas' RE target (as per Table 4.2), or if the South Central RE generation target is derived from the NREL study.

3.5.2 RE target generation methodology by technology type

This section addresses comments on the target generation methodology for the al ternative RE approach as it relates to specific technologies.

Commenters have raised a number of issues related to this subsection which are organized by topics (comments) below. Responses are provided for these topics.

Comment 1: Commenters stated that EPA's Alternative RE Approach methodology is hampered by the lack of data for specific technologies

.53 Response 1: The EPA includes in building block 3 all utility

- scale, zero

- emitting RE technologies that have deployed at significant commercial levels over the past five years

. This decision does not limit or exclude the technologies that are creditable under compliance, including distributed generation resources and offshore wind

. Refer to section VIII of the preamble for additional detail on non

- BSER RE te chnologies

. D istr ibuted generation technologies, as a demand

- side resource, present unique data and technical challenges (such as the role of evaluation, measurement and verification (EM&V) procedures in verifying their production, the diverse economic inc entives of different parties involved in their deployment, and the variety of grid integration policies and conditions across potential deployment sites) that complicate identifying a technically feasible and cost

- effective level of generation. Consequentl y, the EPA is, at this time, choosing not to include distributed technologies as part of the BSER (although, as explained in section VIII of the preamble, distributed RE technologies that meets eligibility criteria may be used for compliance). Additionally , any RE technology that has not been deployed in the United States, including demonstrated RE technologies for which there is clear evidence of technical feasibility and cost

- effectiveness (e.g., offshore wind), contributes no generation to building block 3 under the final methodology that is based on historical capacity deployment. These RE technologies are consequently reserved for compliance, which offers affected EGUs additional flexibility and will reduce their need to rely on other emission reduction measures or building blocks.

The following are summaries of the specific public comments under this comment:

Commenters stated that EPA's Alternative RE Approach methodology is hampered by the lack of data for specific technologies. Commenters noted that because the market potential for distributed generation cannot be tested with the current IPM framework, which only accounts for centralized generation, EPA omits the rapidly growing rooftop solar sector from its analysis. Commenters also noted that the a gency omits offshore wind, despite its significant promise, because there are currently no operational offshore wind facilities from which to determine a baseline development rate. Commenters stated EPA's primary and alternative approaches to renewable ene rgy do not adequately stimulate the market for these technologies.

Comment 2: Commenters stated that the difference between modelling methods for distributed PV versus other renewables is not grounds to exclude distributed PV from building block 3

. Response 2: The EPA includes utility

- scale, zero

- emitting RE technologies that have deployed at significant commercial levels over the past five years

. This decision does not limit or exclude the technologies that are creditable under compliance, including distributed generation resources and offshore wind

. Refer to section VIII of the preamble for additional detail on non

- BSER RE technologies

. Distributed generation technologies, as a demand

- side resource, present unique data and technical challenges (such as the role of evaluation, measurement and verification (EM&V) procedures in verifying their production, the diverse economic incentives of different parties involved in their deployment, and the variety of grid integration policies and conditions54 across potential deployment sites) that complicate identifying a technically feasible and cost

effective level of generation. Consequently, the EPA is, at this time, choosing not to include distributed technologies as part of the BSER (although, as explained in s ection VIII of the preamble, distributed RE technologies that meets eligibility criteria may be used for compliance).

The following are summaries of the specific public comments under this comment:

Commenters noted that EPA stated in the Alternative RE Ap proach Technical Support document that "distributed generation RE technologies were omitted from the Alternative RE Approach because their market potential cannot be tested in the current IPM framework." However,

c ommenters stated that the difference betwe en modelling methods for distributed PV versus other renewables is not grounds to exclude distributed PV from building block 3. Commenters stated that the exclusion of distributed PV on these grounds would be arbitrary and capricious because distributed PV is used to shift generation away from affected EGUs, and it is possible to accurately model distributed PV as part of building block 3. Commenters stated that distributed PV can be included within the IPM model because it is hard

- wired into the model by using the distributed PV capacity projections from the Sunshot

- 62.5% scenario whose projections were calculated using the SolarDS model. Commenters noted that the capacity projections show the amount of solar (GW) that will be built at the given cost assumptions over the default generation mix within the model precisely because distributed PV is more economical. C ommenters stated that the SolarDS mode l inherently includes this comparison of distributed PV to other sources of electricity as it produces the output of solar and that the output of SolarDS based on the cost show that distributed PV should be included within the baseline mix of electricity i n a state

.
Commenters stated that EPA will need to determine which costs to assume for input into the SolarDS model in order to incorporate distributed PV. To this end, c ommenters stated that the EPA should compare the Department of Energy's Sunshot

- 62.5% scenario with current industry trends. Commenters stated that the Sunshot

- 62.5% scenario cost assumptions are $1.88/watt for commercial PV and $2.25/watt for residential PV. Comm enters noted that the latest U.S. Solar Market Insight Report (Q2 2014) shows that commercial distributed PV is currently $2.39/watt and residential distributed PV is currently $3.92/watt. Commenters stated that the decreasing trendline of these current in dustry costs from the SMI report places solar on track to meet the 2030 goals for the

- 75% scenario and to exceed the 2030 goals for the

- 62.5%. Commenters noted that under the

- 62.5% scenario, approximately 67.3 GW of distributed PV will be deployed inste ad of the default electricity mix based on cost by 2030 and stated that this significant level of projected distributed PV deployment based on the trendline of current industry costs demonstrates that distributed PV is reasonable cost when compared to the default electricity mix.

Comment 3: Commenters expressed concern that EPA leaves out two technologies that will likely feature heavily in the future generation mix: distributed solar generation and offshore wind

. Response 3: Distributed technologies, as a demand

- side resource, present unique data and technical challenges (such as the role of evaluation, measurement and verification (EM&V) procedures in verifying their production, the diverse economic incentives of different parties55 involved in their deplo yment, and the variety of grid integration policies and conditions across potential deployment sites) that complicate identifying a technically feasible and cost

- effective level of generation. Consequently, the EPA is, at this time, choosing not to include distributed technologies as part of the BSER (although, as explained in section VIII of the preamble, distributed RE technologies that meets eligibility criteria may be used for compliance). Additionally, any RE technology that has not been deployed in th e United States, including demonstrated RE technologies for which there is clear evidence of technical feasibility and cost

effectiveness (e.g., offshore wind), contributes no generation to building block 3 under the final methodology that is based on hist orical capacity deployment. These RE technologies are consequently reserved for compliance, which offers affected EGUs additional flexibility and will reduce their need to rely on other emission reduction measures or building blocks.

The following are summaries of the specific public comments under this comment:

Commenters noted that EPA leaves out two technologies that will likely feature heavily in the future generation mix: distributed solar generation and offshore wind. Commenters stated that distri buted solar generation will be one of the fastest

- growing segments of renewable energy in South Carolina over the next few years due to the enactment of state legislation (Act 236 of 2014). Commenters urged EPA to consider how to calculate distributed gene ration resources and allow these credits to count towards emission reductions in some manner in addition to utility

scale renewable energy installations. Commenters also noted that South Carolina has tremendous offshore wind potential and that numerous stu dies have documented the positive economic impacts growth in off

- shore wind would have for South Carolina's current manufacturing supply chains if this clean energy sector were expanded, and utility investment costs and impacts on residential, commercial a nd industrial consumers have been documented as well. Commenters stated that while immediate investments in off

- shore wind are not slated for South Carolina, the EPA's inclusion of off

- shore wind as a possible zero

- emission power generating resource that

c ould reduce the state's carbon emissions could encourage South Carolina's utilities to consider these investments in the near future.

Commenters noted that distributed solar is rapidly expanding in the U.S. and its global market is projected to double by 2 023(Navigant Research, Global Distributed Generation Deployment Forecast, (September 2014)) while offshore wind technologies are also rapidly improving world

wide. Commenters noted that IPM does not currently have the capability to calculate economic
const raints for distributed solar and other customer resources, and does not capture potential
progres s in offshore wind development, but still urged that these two resources should be included in target

- setting to provide a more accurate picture of the technic al and economic potential for increased renewable generation.

Commenters noted that the exclusion of distributed resources, especially solar PV, is problematic. Commenters urged EPA to consider alternative ways to include the market potential of this techn ology and noted that the pace of adoption of rooftop solar PV suggests it has significant market potential and would have a meaningful impact on emissions. Commenters also pointed out that dropping the benchmark development rate calculation would allow for the inclusion of offshore wind market potential in the RE generation calculations.56 Comment 4: Commenters expressed concern that the Alternative RE Approach utilizes existing models that fail to consider WTE.

Response 4: The EPA includes utility

- scale, z ero

- emitting RE technologies that have deployed at significant commercial levels over the past five years

. This decision does not limit or exclude the technologies that are creditable under compliance, including distributed generation resources and offshore wind

. Refer to section VIII of the preamble for additional detail on non

- BSER RE technologies.

The following are summaries of the specific public comments under this comment:

Commenters stated that the Alternative RE Approach utilizes existing mod els that fail to consider WTE, despite the fact that existing WTE facilities generate approximately 14,500,000 MWh of electricity per year, while only utilizing 7.6 percent of the nation's waste stream. C ommenters noted that while a state may include elect ricity from WTE facilities in its compliance plan if the alternative renewable goals were adopted, the absence of any mention of WTE in the preamble or the Alternative Renewable Energy Approach TSD sends a signal to states that WTE may not be worth pursuin g. C ommenters thought that this could create a system in which 111(d) picks winners and loser, which is inappropriate.

Commenters opposed EPA's Alternative RE Approach because it does not take into consideration WTE (or biomass) for the purposes of establi shing the best system of emission reduction, nor does it use the levelized cost of energy (LCOE) to determine the cost effectiveness of various technologies.

Comment 5: Commenters commented on the role of biomass under its proposed A lternative RE

. Response 5: The EPA includes in building block 3 all utility

- scale, zero

- emitting RE technologies that have deployed at significant commercial levels over the past five years

. This decision does not limit or exclude the technologies that are creditable und er compliance, including biomass

. Refer to section VIII of the preamble for additional detail on non

- BSER RE technologies.

The following are summaries of the specific public comments under this comment:

Some c ommenters voiced support for excluding biomas s

- burning EGUs from target determinations. Some commenters reasoned that strong RE targets can still be set without justification of the availability of low

- cost biomass; others, stated that EPA's IPM modeling excluded new biopower, and without established methodologies of determining the supply of biomass, it should continue to be excluded from RE target setting. Similarly, other commenter s focused on the inconsistent treatment of the technical potential of biomass under the Alternative RE Approach as comp ared to other renewables in the IPM modeling.

Commenters noted that EPA only models the technical and economic potential of increased wind and solar through its IPM modeling and as a result does not include any new biomass

- burning EGUs in setting the stat es' targets. Commenters stated that EPA should continue to exclude57 biomass

- burning EGUs from target determinations carried out under its proposed Alternative RE Approach for the same reason that they should be explicitly excluded from the proposed approach

. Commenters stated that EPA's Alternative RE Approach demonstrates that strong targets can and should be set without arbitrarily assuming the availability of low

- carbon biomass, especially when updated cost and performance data for wind and solar are inco rporated.

Commenters stated that like the treatment of hydroelectric generation, biomass also receives disparate treatment in the Alternative RE Approach without explanation. Commenters stated the Alternative RE Approach does not take advantage of NREL technical potential data for biomass (including solid biomass from crop, forest, mill residues, urban wood waste, gaseous biomass from animal manure, domestic wastewater treatment plants, a nd landfills), despite the fact that such potential is included in the same NREL report used for other resource types. Commenters stated that the Alternative RE Approach does not include benchmark generation for biomass for each state, instead relies only on expected generation of existing biomass (including landfill gas) using an IPM projection. Commenters stated this treatment of biomass means that the potential for new or expanded biomass capacity is not included in estimates of achievable and cost

effec tive renewable generation. Commenters stated this is particularly concerning given the fact that biomass is most widely available in the southeastern states that otherwise have fewer technically recoverable non

- biomass renewable resources than other region s. Commenters recommended that the final Clean Power Plan include an evaluation of achievable generation from biomass resources, including from new capacity.

Commenters noted that in the alternative approach, the EPA only models the technical and economic potential of expanding wind and solar PV generation through its IPM modeling and does not include new biopower in setting the states' targets. Commenters stated that b ecause available supplies of low

- carbon biomass are likely to be very limited and the EP A has no established or accurate method of how much low

- carbon biomass will be available where and at what price or even how low the net carbon pollution will be, this exclusion is appropriate and should be sustained.

Comment 6: Commenters s uggested EPA fix IPM so it can model cost

- effective hydropower potential and use the results to increase the assumed hydropower potential based on region

specific hydropower potential data

. Response 6: The resources and data provided in this comment were valuable in finalizing the building block 3 methodology

. The EPA has developed new hydropower build options for use in its IPM modeling projections

. For additional detail on new hydropower refer to the GHG Mitigation Measures TSD.

The following are summaries of the specific public comments under this comment:

Commenters suggested EPA fix the Integrated Planning Model (IPM) to estimate cost

- effective hydropower potential and use the results to increase the assumed hydropower potential based on region

- specific hydropower potential data. Commenters stated the noted inability of the IPM to project the economic deployment of new hydropower resources, combined with the methodology58 chosen in the technical and economic potential approach, results in an effect ive ceiling on the renewable energy target for Washington under this approach equivalent to its existing fleet of federal large

- scale dams. Commenters stated no allowance appears to be made for either operational efficiency upgrades at conventional hydropo wer facilities (such as turbine replacement), or the additional hydropower opportunities identified by NREL. Commenters stated that an appropriate hydropower potential for Washington would be a summation of the existing conventional hydropower and addition al potential, along with an allowance for efficiency upgrades at conventional hydropower facilities.

Commenters noted that a recent study provides an appropriate hydropower potential estimate for the Pacific Northwest that is easily adaptable to the propo sed technical potential methodology (118 percent of existing capacity). Commenters stated using these data for the Pacific Northwest, and similar data for other regions, would allow EPA to produce a more realistic hydropower component of this technical pot ential approach. Commenters stated ideally this would be shaped by an economic potential analysis similar to that done for the other renewable energy technologies, and therefore, the IPM should be upgraded to handle hydropower potential, and the appropriat e cost

- effectiveness analysis should be completed by EPA. Commenters stated the results will allow EPA to combine small and large scale hydropower technical and economic potential into a more comprehensive result consistent with the way other renewable tec hnologies are treated.

Comment 7: Commenters recommended that EPA remove existing hydroelectricity from the goal

- setting calculation

. Response 7: The EPA is quantifying final building block 3 target generation levels on the basis of incremental RE only

, including hydropower

. For additional detail on the final methodology refer to section V.E of the preamble and the GHG Abatement Measures TSD.

The following are summaries of the specific public comments under this comment:

Commenters recommended that EPA r emove existing hydroelectricity from the goal

- setting calculation. Commenters noted that including existing hydroelectricity in this approach's goal

setting methodology increases compliance risks, should hydroelectricity decline from baseline levels which is of particular concern for California given the ongoing drought and projected changes to the nature and timing of hydroelectric output in the future due to regulatory changes and climate change. Commenters recognized that existing hydroelectric resources are extremely valuable zero

- carbon resources and should be recognized for the significant roles they play in supporting compliance, but stated that if the Alternative RE Approach is pursued, the approach should exclude existing hydroelectric generation fr om the goal

- setting calculation.

Comment 8: Commenters stated that since hydropower is 45% of the existing RE in this country, the EPA should solidify its position on whether or not hydropower can actually be expanded and included in the computation of BS ER

.59 Response 8: The EPA is quantifying final building block 3 target generation levels on the basis of incremental RE, including hydropower

. The amount of hydropower assumed is the result of observed deployment patterns over the past five years

. For addit ional detail on the final methodology refer to section V.E of the preamble and the GHG Mitigation Measures TSD.

The following are summaries of the specific public comments under this comment:

Commenters noted that the Alternative RE Approach includes an increase in hydropower of 85,224 GWh in 2030, and for the U.S, a 31% increase, but the proposed RE BSER assumes no increase in hydropower due to limited potential and variability although states can includ e it as an option. Commenters stated that since hydropower is 45% of the existing RE in this country, they recommend that U.S. EPA solidify its position on whether or not hydropower can actually be expanded and included in the computation of BSER.

Comment ers noted that NC REPS allows for use of hydropower projects but an increase of 13% is substantial and probably not realistic in North Carolina. Commenters stated that historical values for hydropower are approximately 3.6% of all RE generated in the state from NC RETS tracking system and stated that the inclusion of new hydropower in BSER calculations for North Carolina needs to reflect this level.

Comment 9: Commenters stated there is an error in the calculations for the "Alternat iv e RE Approach" Option 1 regarding hydropower potential

. Response 9: The hydropower ‘technical potential’ and the ‘feasibility determination’ are the same value

. The EPA is not finalizing an approach that relies on this value. Due to commenters concerns, the technical potentia l benchmark has been eliminated in the EPA’s final methodology. For the EPA’s response to this comment, see section V.E of the final rule preamble of the CPP and chapter 4 of the GHG Mitigation Measures TSD for CPP Final Rule..

The following are summaries of the specific public comments under this comment:

Commenters stated there is an error in the calculations for the "Alternative RE Approach" Option 1. Commenters said hydropower potential used for the calculation was intended to use the greater of the fe asibility determination or 2012 generation, as described in the "Alternative RE Approach" technical support document; however, in the accompanying calculation spreadsheet, EPA used the full technical potential. Commenters said although this option should n ot be finalized, this error should be addressed if EPA does so.

Comment 10: Commenters stated Building Block 3 should calculate the contribution from all adequately demonstrated renewable energy technologies

. Response 10 : The EPA includes in building block 3 all utility

- scale, zero

- emitting RE technologies that have deployed at significant commercial levels over the past five years

. This60 decision does not limit or exclude the technologies that are creditable under compliance

. Refer to section VIII of the preamble for additional detail on non

- BSER RE technologies.

The following are summaries of the specific public comments under this comment:

Commenters stated Building Block 3 should calculate the contribution that renewable en ergy can make to reduced emissions at affected EGUs by evaluating the technical and cost

- effective potential of all adequately demonstrated renewable energy technologies. Commenters stated the Alternative RE Approach, as proposed, does not include the pote ntial of distributed rooftop solar PV or offshore wind, and does not fully consider the potential for new hydroelectric or biomass generation.

Commenters stated the Alternative RE Approach does not include distributed solar in calculating either benchmark generation or IPM

- projected renewable generation, yet, distributed solar PV is both technically feasible and adequately demonstrated. Commenters stated that from 2012 to 2013, installed distributed PV grew 17 percent overall and 68 percent in the resident ial sector. Commenters also referenced a recent analysis by Deutsche Bank that shows that distributed PV has reached grid parity in regions within at least 10 states. Commenters strongly recommended that EPA incorporate this increasingly important segment of the renewable energy market into the Alternative RE Approach. Commenters stated t he Agency should either incorporate distributed PV into its IPM modeling or simply use the NREL technical potential study as the basis for calculating each state's technica lly feasible, cost

- effective generation from distributed PV. Commenters stated the latter approach is consistent with the method EPA used to calculate the potential for new hydroelectric generation.

Comment 11: Commenters stated that the benchmark development rate should be removed from the methodology.

Response 11: The EPA agrees with the comment

. The benchmark development rate has been eliminated in the EPA’s final methodology for building block 3.

The following are summaries of the specific public comments under this comment:

Commenters stated that the Alternative RE Approach, when adjusted, captures the emissions reductions achievable through application of the BSER to covered sources most effectively. Commenters said the Alternative RE Appr oach is more accurate because the approach does not rely on one policy to determine the solar potential in a state, as the RPS approach does; thus the Alternative RE Approach would set a more realistic expectation of the amount of solar growth feasible tha t will create a balanced energy portfolio in each state. Commenters stated The Natural Resource Defense Council (NRDC) engaged with ICF to run the Integrated Planning Model (IPM), the same model that EPA uses, to reproduce EPA's RE Market Potential run bas ed on the below solar energy recommendations, using up

- to

- date cost and performance assumptions for renewable energy technologies. Commenters said the resulting national target for renewable generation nearly doubles from EPA's approaches, growing from 520

- 530 TWh to ~930 TWh. Commenters said this clearly demonstrates that significantly higher levels of renewable energy are both technically and economically achievable, compared to the levels proposed in either of61 EPA's target

- setting approaches. Commenters said based on these results, EPA should strengthen the contributions of renewable energy in its target

- setting to accurately reflect the full potential that these technologies can have in reducing dangerous carbon pollution from the electricity
sector.

Com menters added as the EPA notes in its proposal, applying NREL's technical potential for solar in each state to determine the state goals has limited value. Commenters believe d that the technical potential is arbitrary because it shows the solar capacity th at could be built in a given state without recognizing real

- world limiting factors such as economic growth and grid constraints; therefore, the EPA should not rely on NREL's technical potential for setting state goals.

Commenters added the EPA should solely rely on the IPM model for setting the state targets; unlike the technical potential, the IPM model takes into account the cost of building renewable generation, as well as grid conditions in a state and a number of other factors ; in addition, the IPM model considers the resource potential that is considered by NREL's technical potential. Commenters believe d that with the correct solar data inputs, the IPM model provides a realistic projection of solar energy potential at the stat e level that can be relied upon for setting state goals.

Commenters added there is precedent to rely solely on the IPM model for setting the renewable targets i n each state under the A lternative RE A pproach. Commenters said the EPA currently uses the IPM model to analyze the impact of air emissions policies on the U.S. electric power sector such as the Clean Air Interstate Rule, Cross

- State Air Pollution Rule (CSAPR), the Mercury and Air Toxics Standards (MATS), and the proposed Carbon Pollution Standards for New Power Plants. Commenters said the EPA also notes that "for the development of its latest power sector modeling platform, EPA has increased its external engagement with state air quality planning officials, power company representatives, regional tr ansmission organizations, and others who have provided input on the data, assumptions, and structure of EPA's Power Sector Modeling Platform v.5.1," which shows that the model includes feedback from a variety of stakeholders, and can be used reliably to se t the state targets for compliance.

Comment 12: Commenters recommended that EPA include estimates of achievable offshore wind in the Alternative RE Approach.

Response 12: Any RE technology that has not been deployed in the United States, including demons trated RE technologies for which there is clear evidence of technical feasibility and cost

effectiveness (e.g., offshore wind), contributes no generation to building block 3 under the final methodology that is based on historical capacity deployment. These RE technologies are consequently reserved for compliance, which offers affected EGUs additional flexibility and will reduce their need to rely on other emission reduction measures or building blocks.

The following are summaries of the specific public comm ents under this comment:

Commenters stated the Alternative RE Approach does not include estimates of feasible and cost effective offshore wind. Commenters stated while offshore wind is relatively new to the United62 States, it is well established globally with a market that added over 1,700 MW in 2013, bringing total installed capacity to 7,031 MW. Commenters stated that in the United States, DOE has estimated the potential capacity of offshore wind turbines in U.S. w aters at 4,150 GW, four times the electric generating capacity from all sources nationwide in 2008, and while no projects have reached completion yet in the United States, there are 4,900 MW of proposed projects in advanced stages of planning. Commenters r ecommended that EPA include estimates of achievable offshore wind in the Alternative RE Approach. Such estimates can be based on global development rates.

3.5.3 Potential alternative method using technical and economic potential

This section addresses com ments on the target generation methodology for the alternative RE approach as it relates to technical and economic potential

. Commenters have raised a number of issues related to this subsection which are organized by topics (comments) below. Responses ar e provided for these topics.

Comment 1: Commenters supported EPA's efforts to incorporate the technical and economic potential of renewable energy in each state in the methodology for target

- setting in Building Block 3.

Response 1: The resources and data provided in this comment were valuable in finalizing the building block 3 methodology. The final building block 3 methodology does not rely on state

specific deployment estimates, but rather cost

- effective RE at an interconnection level

. The basis for building block 3 target generation levels is the observed pattern of historical development for each of the BSER RE technologies

. Modeling projections remain an important aspect of the overall methodology in validating the technical feasibility and cost

- ef fectiveness of the target generation level. The EPA addresses considerations related to the technical feasibility and associated grid integration costs of significant RE penetration in both the preamble (section V.E) and GHG Mitigation Measures TSD

.

The following are summaries of the specific public comments under this comment:

Commenters supported EPA's efforts to incorporate the technical and economic potential of renewable energy in each state in the methodology for target

- setting in Building Block 3. Commenters stated that the potential alternative method using technical and economic potential is the most analytically sound of the approaches considered by EPA, but offered suggestions on how to improve upon the approach. Commenters stated that to correc tly perform an avoided cost analysis, EPA should run models at the state or regional level similar to the models used by utilities performing the Integrated Resource Planning ("IRP") modeling, including RE options (including capital, operating costs, opera ting characteristics and a CO2 price less than the Social Cost of Carbon at a 5 percent discount rate). Commenters noted that if the model selects RE sources, EPA should take the generation plan from the IRP modeling and insert it into a production cost mo del (such as ProMod or Aurora) to project the production cost by year,63 remove the RE component from the input of the production cost model and run the model again, requiring it to meet electricity load with other existing sources that include carbon costs and other production costs, and take the difference in production costs to determine the avoided energy costs/MWh for RE. Commenters noted that if the model does not pick RE, then RE should be forced into the model outputs by taking the generation plan fr om the model including the forced RE output and then use in a production cost model (such as ProMod or Aurora) to project the production cost by year, removing the RE component from the input of the production cost model and run the model again, requiring it to meet electricity load with other existing sources, including the carbon costs and other production costs, and taking the difference in production costs to determine the avoided energy costs/MWh for RE.

Commenters recommended that EPA adopt the Alte rnative RE Approach which reflects state and regional technical and economic potential, but asked that EPA improve the approach by using more accurate and updated cost and performance data for renewable energy technologies, removing the benchmark utilizati on rate, and allocating targets based on each state's share of regional CO2 emissions.

Commenters noted that EPA should focus on establishing instate renewable generation that is based upon technical and economic potential for the expansion of renewable ge neration with the boundaries of the individual state and reallocated within the regional nature of the RPS market's alignment with dispatch of electricity by the RTO/ISO.

Commenters stated that since this approach used detailed supply curve information fro m many locations, it broadly seems more consistent with cost

- effective compliance than the primary and alternative methods but noted that there is insufficient evidence about the precise methodology or its results to make definitive assertions about the re lative merits and transparency of this approach.

Commenters stated that this alternative should not set a larger target for RE and additional hydropower should be included.

Comment 2: Commenters supported the alternative method for calculating the renewa ble energy portion of the BSER, but with a modification to use regional technical and economic potential for each technology.

Response 2: The resources and data provided in this comment were valuable in finalizing the building block 3 methodology. The final building block 3 methodology does not rely on state

specific deployment estimates, but rather cost

- effective RE at an interconnection level

. The basis for building block 3 target generation levels is the observed pattern of historical development for each of the BSER RE technologies

. Modeling projections remain an important aspect of the overall methodology in validating the technical feasibility and cost

- effectiveness of the target generation level. The EPA’s final methodology uses updated cost and p erformance data from NREL for onshore wind and solar resources and does not include the technical potential limiter referenced by the above commenters

. The EPA addresses considerations related to the technical64 feasibility and associated grid integration co sts of significant RE penetration in both the preamble (section V.E) and GHG Mitigation Measures TSD.

The following are summaries of the specific public comments under this comment:

Commenters supported the alternative method for calculating the renewable energy portion of the BSER, but with a modification to use regional technical and economic potential for each technology.

Commenters stated that the technical and economic potential approach, as outlined in the Alternative BB3 technical support documents and supplemented by the NODA, offers important advantages over the renewable portfolio standard (RPS) method for calculating Building Block 3 if EPA makes certain critical technical revisions to the analysis. Commenters believed that this approach will better reflect the reality of interstate power transactions. Commenters stated that using a regional technical and economic approach will ameliorate challenges that the original proposal presented for some states that export renewable energy, as it would allow use of out

- of

state renewables for compliance. Commenters stated that establishing state Building Block 3 targets by apportioning re gional renewable energy potential based on state power consumption would result in states with larger loads being responsible for capturing a larger proportional share of the regional renewable energy potential and while this does not entirely eliminate th e imbalance between a generation

- based baseline and consumption

- based compliance crediting, it reduces its impact and is likely the best, most feasible approach for EPA to address this challenge in the absence of nation

- wide all

- source consumption tracking systems.

Commenters noted that certain technical revisions would be needed in order for the technical and economic potential analysis to reflect what level of renewable energy will actually be achievable and cost

- effective during the compliance period.

Commenters stated first that EPA should allow its economic potential analysis alone to determine what levels of renewable energy growth are economically reasonable because EPA's current Alternative RE Approach sets a redundant and arbitrary growth cap base d on a percentage of technical potential per year. Commenters noted that this cap is not
necessary because the economic potential analysis serves to limit growth expectations to economically reasonable and practicable levels that factor in infrastructure c onstraints. Commenters also noted that because the cap is historically

- based, it will likely not capture technology improvements and therefore will fail to reflect the increasing economic potential of renewable energy.

Commenters noted secondly that EPA s hould make significant improvements in its assumptions regarding the present and future cost of renewable energy as they should, at a minimum, reflect current, real

- world cost assumptions. Commenters recommended that EPA align its assumptions with the cost s reflected in the most current reports by the U.S. Department of Energy (U.S. DOE) for solar and the Lawrence Berkeley National Laboratory (LBNL) for wind energy. Commenters cited a study by the Natural Resources Defense Council that found that simply by updating the cost and performance parameters for renewable generation and energy efficiency to be consistent with today's technologies, compliance could be achieved at net savings of $1.8 billion in 2020 and $6.6 billion in 2030. Commenters stated that acc urately reflecting today's costs is a65 necessary improvement, but EPA should go a step further to gain an accurate picture of what levels of renewable energy will actually be achievable and cost

- effective during the compliance period by applying US DOE and LBNL future supply curve predictions to prevent its out

- year assumptions from being overly conservative.

C ommenters stated that to the extent feasible in the technical and economic potential modeling, EPA should expect that grid changes will enable even m ore cost

- competitive renewable energy by 2030. Commenters stated that by then, generator retirements and new transmission builds will have opened transmission capacity for more cost

- effective renewable energy, and improved coordination and market functions will have improved transmission operations.

Commenters supported a regionalized technical and economic approach, but suggested the following improvements to this approach: (1) remove the "technical resource" step in which it imposes an arbitrary cap on th e percentage of the technical renewable resource that can be developed in a state or region; (2) in quantifying which renewable energy resources are economic, EPA should begin with current, real

- world data on the cost of renewable energy technologies; (3) for projecting changes in the economics and performance of renewable energy through the year 2030, EPA should rely on the detailed and thoroughly peer

- reviewed cost and performance projections developed through the Department of Energy and the National Ren ewable Energy Laboratory; (4) in its economic modeling, EPA should not impose a firm cap on the percentage of variable (wind and solar) renewable energy that can be deployed in a state or region, but rather should economically model the cost of renewable c urtailment that could occur at extremely high renewable energy penetrations; and (5) changes to the generation mix and other power system changes that are expected to occur between now and 2030, including those that are triggered by the provisions of 111(d ) itself, should also be included in the analysis of the economics of higher renewable penetrations. Commenters urged EPA to exclude the technical potential benchmark from the A lternativ e RE A pproach and rely solely on the Integrated Planning Model (IPM) m odel results, which would produce a more accurate representation of likely future development and noted that EPA has previously relied on the IPM model to analyze the impact of other air emissions policies on the US power sector.

Comment 3: Commenters rec ommended that EPA develop a methodology that uses regional potentials for technologies as opposed to state

- by

- state assessments

. Response 3 : The resources and data provided in this comment were valuable in finalizing the building block 3 methodology. The final building block 3 methodology does not rely on state

specific deployment estimates, but rather cost

- effective RE at an interconnection level

. The basis for building block 3 target generation levels is the observed pattern of historical development for each of the BSER RE technologies

. Modeling projections remain an important aspect of the overall methodology in validating the technical feasibility and cost

- effectiveness of the target generation level. The EPA’s final methodology uses updated cost and p erformance data from NREL for onshore wind and solar resources and does not include the technical potential limiter referenced by the above commenters

. The EPA addresses considerations related to the technical feasibility and associated grid integration co sts of significant RE penetration in both the preamble (section V.E) and GHG Mitigation Measures TSD.66 The following are summaries of the specific public comments under this comment:

Commenters provided background information on renewable energy resources, policies, and tracking system in use in the state of Oregon. Commenters generally supported the conceptual framework of using technical and economic potential to quantify renewable energy gener ation for purposes of setting state goals, as discussed in the Alternative Renewable Energy Approach TSD. Commenters recommended that EPA develop a methodology that uses regional potentials for technologies as opposed to state

- by

- state assessments, such as the methodology discussed in section 1.4 of the Alternative Renewable Energy Approach TSD.

In addition, c ommenters stated EPA should design a methodology that does not apply a development rate constraint to the potential renewable energy available as pro posed in the alternative methodology. Commenters using cost

- effective potential reflects the actual opportunity for expanding renewable resources in any given region or state. Commenters stated further constraints are unnecessary. Commenters stated that th is modified alternative renewable energy approach has several merits. Commenters stated a methodology using technical and economic potential more accurately reflects the availability of cost

- effective renewable energy compared to the proposed approach of u sing RPS requirements already established by states. Commenters stated RPS is a specific policy instrument whose stringency varies widely for reasons often unrelated to the cost or availability of renewable energy. Commenters generally, renewable power can flow within a region, not just within the state in which it is sited. Commenters stated using a regional technical and economic potential for technologies will help to average out anomalous state

- level results and generate state

- level targets that are mor e indicative of states' ability to cost effectively develop renewable power to serve their demand. Commenters stated apportioning a regional average potential for renewable energy to states based on their share of the regional electric load provides a bett er indication of states' abilities to invest in renewable energy to serve their loads as these investments are likely to site the renewable energy within the region but may not occur within the borders of the state making the investment. Commenters stated a regional approach to this building block ensures greater symmetry between tools available for compliance and the methodology used to construct the BSER.

Comment 4: Commenters stated that EPA should not use the Technical Potential as a comparison point as an input to the determination of the targets in the RE Alternative Proposal

. Response 4: The EPA has removed the technical potential limiter from the final methodology for building block 3 target generation level.

The following are summaries of the specific public comments under this comment:

Commenters stated that EPA should not use the Technical Potential as a comparison point as an input to the determination of the targets in the RE Alternative Proposal, because almost by definition the Technical Potential is never expected to be realized in any scenario as it does not consider costs or other barriers to resource development, but only the physical potential for deployment. Commenters noted that a more appropriate approach would be for the EPA to67 co mpare RE targets to the "Economic Potential" of RE, which is defined in the IPCC's Fourth Assessment Report as follows: "'economic potential'" is defined as the potential for cost

- effective GHG mitigation when non

- market social costs and benefits are inclu ded with market costs and benefits in assessing the options for particular levels of carbon prices in US$/tCO2 and US$/tC

eq. (as affected by mitigation policies) and when using social discount rates instead of private

ones

. Commenters stated t his includes externalities (i.e. non

- market costs and benefits such as environmental co

- benefits)."

Comment 5: Commenters supported EPA's technical and economic potential approach, but stated that EPA needed to use more robust and up

- to

- date data in its analysis.

R esponse 5: The resources and data provided in this comment were valuable in finalizing the building block 3 methodology. The EPA updated cost and performance data for onshore wind and solar technologies for the analysis supporting the final building block 3 generation levels

. For more information, refer to section V of the preamble and Chapter 4 of the GHG Mitigation Measures TSD.

The following are summaries of the specific public comments under this comment:

Commenters supported EPA's technical and economic potential approach, but stated that EPA needed to use more robust and up

- to

- date data in its analysis. Commenters stated an advantage of the renewable energy approach based on technical and economic potenti al, as described in the Alternative RE Approach TSD, is that it can avoid the myriad of complexities inherent in RPS policies. Commenters stated however, it must be based on current data and robust regional analysis. Commenters recognized that EPA likely l acks the time to complete a more thorough technical potential analysis, and c ommenters cannot, in good conscience, recommend an approach resulting in the Washington targets produced by EPA's analysis. Commenters stated the 2012 existing renewable energy (e xcluding existing hydropower) level of 7 percent is identical to the 2020 target and the 2030 target, both of which are also 7 percent (excluding existing hydropower). Commenters encouraged EPA to continue developing robust data and analysis that would bet ter support this approach, and would help inform states of their options as they chart compliance paths using renewable energy. Commenters recommended several adjustments to the approach.

Commenters stated th at the analysis underlying the Alternative RE A pproach needs to be updated to reflect current technologies (such as taller wind turbines and distributed generation) and current costs (which are falling rapidly) and that an up

- to

- date analysis of the technical and economic potential for renewable energy to cut carbon pollution will provide a strong legal and technical foundation for the Clean Power Plan, and help facilitate our transition to the clean
energy

- fueled economy of the future.

Comment 6: Commenters expressed concern regarding pathways for individual states to access
out

- of

- state renewable generation for compliance.68 Response 6: Refer to section VIII of the final rule preamble of the CPP for detailed guidance on how affected EGUs access out

- of

- state incremental RE in demonstrating compliance

. The following are summaries of the specific public comments under this comment:

Commenters stated that if the Final Rule does not make available clear, unilateral pathways for individual states to access out

- of

- state renewable generation for compliance, then they recommend that EPA further develop the state

- specific technical and economic potential pathway and make it available for comment before it is finalized so that stakeholders can better compare this method to the other two RE approaches (regional a nd benchmarking) described by EPA.

Comment 7: Commenters expressed concern that EPA did not include distributed solar, offshore wind, or low

- carbon biomass in setting state targets in its technical and economic alternative approach for determining renewable targets

. Response 7: The EPA includes in building block 3 all utility

- s cale, zero

- emitting RE technologies that have deployed at significant commercial levels over the past five years

. This decision does not limit or exclude the technologies that are creditable under compliance, including distributed generation resources and offshore wind

. Refer to section VIII of the preamble for additional detail on non

- BSER RE technologies

. Distributed generation technologies, as a demand

- side resource, present unique data and technical challenges (such as the role of evaluation, measuremen t and verification (EM&V) procedures in verifying their production, the diverse economic incentives of different parties involved in their deployment, and the variety of grid integration policies and conditions across potential deployment sites) that compl icate identifying a technically feasible and cost

- effective level of generation. Consequently, the EPA is, at this time, choosing not to include distributed technologies as part of the BSER (although, as explained in section VIII of the preamble, distribut ed RE technologies that meets eligibility criteria may be used for compliance). Additionally, any RE technology that has not been deployed in the United States, including demonstrated RE technologies for which there is clear evidence of technical feasibili ty and cost

- effectiveness (e.g., offshore wind), contributes no generation to building block 3 under the final methodology that is based on historical capacity deployment. These RE technologies are consequently reserved for compliance, which offers affecte d EGUs additional flexibility and will reduce their need to rely on other emission reduction measures or building blocks. The following are summaries of the specific public comments under this comment:

Commenters noted that EPA did not include distributed solar, offshore wind, or low

- carbon biomass in setting state targets in its technical and economic alternative approach for determining renewable targets. Commenters stated that these technologies are either already growing rapidly (distributed solar) or a re of particular interest to certain regions (such as offshore wind for the East Coast and biomass for the Southeast).69 Comment 8: Commenters expressed concern that use of a state's technical and economic potential ignores the interstate nature of renewabl e electricity

. Response 8: The final building block 3 methodology does not rely on state

- specific deployment estimates, but rather cost

- effective RE at an interconnection level

. Refer to section V of the final rule preamble of the CPP for additional infor mation.

The following are summaries of the specific public comments under this comment:

Commenters stated that use of a state's technical and economic potential avoids setting the goal based on renewable energy policies; however, this potential

- based approach ignores the interstate nature of renewable electricity and the fact that utilities and other en tities frequently purchase RE from other states with higher RE potential which leads to serious inequity issues and also may fail to acknowledge existing investments in out

- of

- state RE. Commenters noted that a potential

based approach requires enormous amo unts of investment from states that have large technical and economic potentials (such as the Plains states) but would require very little of states that have low RE potentials, despite the fact that such states could invest in RE development in other
stat es with higher potential. Commenters were also concerned that because the alternative technical and economic potential approach is based on potential within a state, EPA may only permit in

- state RE generation to count for compliance under this approach. Co mmenters stated that it is essential that they and other stakeholders be able to use out

- of

- state RE for compliance.

Comment 9: Commenters suggested the EPA set the target for the renewable technical and economic potential approach as an energy target exp ressed in MWh

. Response 9: The final building block 3 target generation level is an energy target expressed in MWh at the level of the interconnection

. Refer to section V.E of the preamble and the GHG Mitigation Measures TSD for additional detail.

The following are summaries of the specific public comments under this comment:

Commenters suggested th at EPA set the target for the renewable technical and economic potential approach as an energy target expressed in MWh. Commenters stated targets based on
po tential are not meaningful as a percentage of in

- state generation, because technical potential is based on technology specific research and geographic characteristics. Commenters also stated in

state generation can fluctuate wildly in hydropower dominant s tates like Washington. Commenters stated if desired, a specific energy target can be converted to a percentage of a states' retail sales (i.e., load). Commenters stated basing the percentage on retail sales instead of generation will have less variance ove r time and serves as a better base for renewable energy target setting than using in

- state generation.

Comment 10: Commenters suggested that there may be ways to build "caps" and "floors" into the assignment of technical and economic potential to address this disparity

.70 Response 10: The EPA believes the state

- level disparity cited by the commenter is addressed through a final building block 3 methodology that does not rely on state

- specific deployment estimates, but rather cost

- effective RE at an interconnection level. The final building block 3 methodology is described in detail in V.E of the prea mble and in the GHG Mitigation Measures TSD.

The following are summaries of the specific public comments under this comment:

Commenters recognized that the technical and economic potential of RE development is not evenly distributed among the states and su ggested that there may be ways to build "caps" and "floors" into the assignment of technical and economic potential to address this disparity. Commenters noted that such upper and lower bounds could acknowledge the practical limitations of development in c ertain high potential states while also preventing other states with lower potential from backsliding to a level of RE generation that is less than what they had achieved in 2012.

Comment 11: Commenters urged EPA to include load growth when economically m odeling renewable energy growth and examining the reliability of higher renewable penetrations

. Response 11: Load growth is accounted for in the modeling that supports building block 3.

The following are summaries of the specific public comments under thi s comment:

Commenters urged EPA to include load growth when economically modeling renewable energy growth and examining the reliability of higher renewable penetrations. Commenters noted that load growth is a critically important factor that drives generation expansion decisions, yet it was not accounted for in EPA's proposed method for setting the renewable energy component of building block 3 and if EPA moves to a technical and eco nomic approach for setting the renewable energy target, EPA should make sure to include load growth in its economic modeling. Commenters stated that this will ensure that the modeling of expanded renewable generation more accurately reflects the power syst em that will exist when the renewable generation is added, in addition to taking fuel price changes, generator additions and retirements, transmission upgrades, grid operating reforms, and other power changes into account

.

Comment 12: Commenters expressed concern that using technical and economic potential relies

on energy cost calculations that include avoided costs for environmental externalities

. Response 12: The basis for building block 3 target generation levels is the observed pattern of historical development for each of the BSER RE technologies

. Modeling projections remain an important aspect of the overall methodology in validating the technical feasibility and cost

effectiveness of the target generation level. The final building block 3 methodolo gy is described in detail in V.E of the preamble and in the GHG Mitigation Measures TSD.

The following are summaries of the specific public comments under this comment:71 Commenters noted that the potential alternative method using technical and economic potential relies on energy cost calculations that include avoided costs for environmental externalities. Commenters stated that, given the difficulties in quantification for some, do these need to be calculated in all cases? Commenters also asked if EPA intend to issue further guidance on this issue.

3.5.4 State

- level results

This section addresses comments on the target generation methodology for the alternative RE approach as it rel ates to specific states.

Commenters have raised a number of issues related to this subsection which are organized by topics (comments) below. Responses are provided for these topics.

Comment 1: Commenters stated that the 2030 targets set for Alaska and H awaii of 1,738 GWh and 2,600 GWh, respectively, are probably too low

. See sections V.A.3 and 4 in preamble to CPP Final Rule.

Response 1: The EPA has not expressed a building block 3 requirement associated with Hawaii or Alaska

. For additional detail on this decision, refer to section V of the preamble.

The following are summaries of the specific public comments under this comment:

Commenters stated that the 2030 targets set for Alaska and Hawaii of 1,738 GWh and 2,600 GWh, respectively, are probably too low. Commenters stated that selecting the 2002 to 2012 period for determining a growth factor discounts recent experience, which, according to the
commenter s , is more indicative of the market potential of wind and solar in Alaska and Hawaii. Commenters not ed that according to EIA data, Hawaii had solar thermal and PV generation in 2011 of 3,593 MWh, in 2012 of 4,608 MWh, and in 2013 of 29,385 MWh and that for the first 8 months of 2014 Hawaii has 35,830 MWh of solar thermal and PV generation. Commenters
sta ted that the same data for wind tells a similar story of recent growth with 2011 generation of 340,812 MWh, 2012 of 378,234 MWh, 2013 of 461,417 and the first 8 months of 2014 having 349,851 MWh. Commenters inferred through this information that Hawaii's t arget is too low in view of the exclusion of recent growth in 2013 and 2014. Commenters suggested that a better target for Hawaii may be the use of the state's RPS target of 40% in 2030.

Commenters noted that a similar dynamic exists in Alaska, where wind production in 2011 was zero, in 2012 was 37,393 MWh, and in 2013 was 141,751 MWh and that for the first 8 months of 2014 Alaska has 107,919 MWh. It is likely that Alaska's market potential for RE is greater than the target reflects.72 Comment 2: Commenter s stated that the higher levels of renewable generation, in combination with the reduction in retired coal fired capacity, reduce the amount of new natural gas fired generation needed to meet future load and reserve margins requirements in Arizona.

Respons e 2: The final building block 3 methodology does not rely on state

- specific deployment estimates, but rather cost

- effective RE at an interconnection level

. The EPA addresses considerations related to the technical feasibility and associated grid integratio n costs of significant RE penetration in both the preamble (section V.E) and GHG Mitigation Measures TSD.

The following are summaries of the specific public comments under this comment:

Commenters noted that EPA's Alternative RE Approach assumes significantly higher levels of installed renewable capacity from 2020 through 2030 for Arizona, and under this scenario, the assumed installed renewable capacity reflects a level more in line with the Arizon a renewable energy standard which assumes 15% of a load serving entity retail load is sourced from renewable resources. Commenters stated that the higher levels of renewable generation, in combination with the reduction in retired coal fired capacity, redu ce the amount of new natural gas fired generation needed to meet future load and reserve margins requirements in Arizona.

Comment 3: Commenters stated that for Hawaii, this proposed Alternative RE A pproach is problematic.

Response 3: The EPA has not expr essed a building block 3 requirement associated with Hawaii

. For additional detail on thi s decision, refer to section V of the preamble. See sections V.A.3 and 4 in preamble to CPP Final Rule.

The following are summaries of the specific public comments under this comment:

Commenters noted t hat for Hawaii and Alaska, the A lternative RE A pproach is calculated from the difference between RE generation in 2002 and 2012 and an annual average growth rate is calculated which is applied between the 2020 to 2030 time frame. Commenters stated that for Hawaii, this proposed Alternative RE A pproach is problematic as Hawaii experienced anomalously high exponential growth during the period between 2002 and 2012.

Commenters noted that the fixed growth rate does not acc ount for the increasing technical and economic challenges that arise as more RE is added to the electrical grid. Commenters noted that page 6 of the "Alternative RE Approach" TSO refers the reader to "Chapter 4 of the GHG Abatement Measures TSO for further detail on the calculation of RE growth factors for Alaska and Hawaii", however, as indicated on Page 4

- 18, the only justification provided for this approach is that it was "due to the unique location" of Alaska and Hawaii. Commenters stated that neither t he "Alternative RE Approach" nor "GHG Abatement Measures" TSDs address the potential uncertainty associated with basing annual growth factors for 2020 to 2030 on the difference between 2002 and 2012 RE generation. Therefore, c ommenters believed that the
ap plication of EPA's approach for estimating potential RE growth is insufficiently justified and did not recommend the use of this Alternative RE A pproach for quantifying RE generation as73 BSER for Hawaii. Commenters stated that the RE estimates Hawaii, wheth er fixed or with growth (under the Alternat iv e RE Approach), do not account for "technical and market potential.

Commenters additionally noted that there are also conflicting values specified for Hawaii's RE generation growth factor that is discussed in th e "Technical Support Document (TSD) for Carbon Pollution Guidelines for Existing Power Plants: Emission Guidelines for Greenhouse Gas Emissions from Existing Stationary Sources: Electric Utility Generating Units," Docket ID No. EPA

- HQ

- OAR

- 2013

- 0602 and "GH G Abatement Measures." Commenters noted that on Page 4

- 18 of "GHG Abatement Measures," it is stated in the text that the RE growth factor for Hawaii is 8% and in Table 4.5 of the same page, the value given is 9%. Commenters stated that since Table 4.5 is n ot referenced in the text, while it appears to conflict with the 8% value, the 9% value may refer to something else. C ommente rs also noted that the "Alternative RE Approach" TSD references the "GHG Abatement Measures" TSD when noting the annual growth fact or for Hawaii was calculated to be 7.9%. Commenters noted that after the 10 year period from 2020 through 2029, the renewable energy based on a 9% annualized growth rate is approximately 10% larger than that of a 7.9% growth rate.

Comment 4: Commenters stated that the Alternative RE Approach targets for Idaho and Washington are completely unrealistic.

Response 4: The final building block 3 methodology does not rely on state

- specific deployment estimates, but rather cost

- effective RE at an interconnection level

. The basis for building block 3 target generation levels is the observed pattern of historical development for each of the BSER RE technologies

. The EPA addresses considerations related to the technical feasibility and associated grid integration costs of significant RE penetration in both the preamble (section V.E) and GHG Mitigation Measures TSD that support the final CPP

. The following are summaries of the specific public comments under this comment:

Commenters noted that EPA's Alt ernative RE Approach target for Idaho is about seven times larger than the EPA's Proposed RE Approach target for Idaho and that the Alternative RE Approach's target for Idaho is 1,314% larger than affected unit generation and is the largest target of all s tates on a percentage basis. Commenters noted that if EPA decides to use its Alternative RE Methodology Targets, 13 states would need to acquire RE generation at levels over 35% of total generation to meet the Alternative RE Targets, which is a level that no state (including California) considered when setting their RPS targets. Commenters added that the Alternative RE Approach targets for Idaho and Washington, which respectively are 139% and 208.9% of 2012 total generation, are completely unrealistic and require RE levels that are disproportionate to affected unit generation and ignore cost and reliability impacts. Commenters stated that EPA should not consider its Alternative RE Methodology targets.

Comment 5: Commenters agreed that EPA's Alternative RE Approach can provide Iowa with a meaningful compliance obligation under the rule

.74 Resp onse 5: The final building block 3 methodology does not rely on state

- specific deployment estimates, but rather cost

- effective RE at an interconnection level

. The EPA addresses considerations related to the technical feasibility and associated grid integra tion costs of significant RE penetration in both the preamble (section V.E) and GHG Mitigation Measures TSD that support the final CPP

. The following are summaries of the specific public comments under this comment:

Commenters noted that EPA's Alternative RE Approach, excluding hydropower, would change Iowa's 2020 interim target emissions rate from 1,341 lbs/MWh to 1,056 lbs/MWh and the state's final target in 2030 from 1,301 lbs/MWh to 906 lbs/MWh but stated that by simply accounting for actions taken or planned to date and continuing energy efficiency programs in the state, Iowa's emission's rate in 2030 will be 1,109 lbs/MWh. Commenters stated therefore that the relevant increase in stringency for Iowa is not from 1,301 lbs/MWh to 906 lbs/MWh but from 1, 109 lbs/MWh to 906 lbs/MWh. Commenters agreed that EPA's Alternative RE Approach can provide Iowa with a meaningful compliance obligation under the rule and would help ensure the state begins to maximize its cost

- effective and technically feasible carbon r eduction potential, but stated that the approach does not result in high enough levels of renewable energy in Iowa. Commenters stated that when taking into account EPA's benchmark development rate under the Alternative RE Approach, Iowa's 15,878 GWh target for renewable energy in 2020 under the approach is less than the 18,536 GWh of generation that Iowa will have, at a minimum , i n 2020.

Comment 6: Commenters disagreed with EPA's assessment of Kansas' renewable energy generation when developing state goals under the Alternative RE Approach.

Response 6: The final building block 3 methodology does not rely on state

- specific deploym ent estimates, but rather cost

- effective RE at an interconnection level

. The EPA addresses considerations related to the technical feasibility and associated grid integration costs of significant RE penetration in both the preamble (section V.E) and GHG Mi tigation Measures TSD that support the final CPP.

The following are summaries of the specific public comments under this comment:

Commenters disagreed with EPA's assessment of Kansas' renewable energy generation when developing state goals under the Altern ative RE Approach. Commenters stated that EPA's conclusions for Kansas under the alternative methodology for establishing states' renewable requirements based upon an EPA assessment of "what's possible" for the states as identified in the November 16, 2014 NODA produce absurd results. Commenters noted that the increased requirement for renewable production in 2030 (50,900,000 MWh) is a 470% increase in the original 2030 requirements for Kansas, fully 170% higher than the 2030 (29,980,000 MWh) fossil energy target for the state. Commenters stated that the primary limitations on Kansas wind production are related to SPP

- evaluated reliability impacts and constrained transmission access and in order to enable the alternative renewable requirement for Kansas, c om menters conservatively estimated that the required cost of transmission construction to move such75 amounts of wind energy (in Kansas alone) is $6.5 billion, which exceeds the entire forecasted reliability

- based construction estimates of the entire SPP betwe en now and 2020 ($6.4 billion).

Commenters noted that based on the data contained in EPA's TSD, Kansas had a 2012 starting point of 5,263 GWh of renewable energy generation out of a total 2012 generation of 44,425 GWh. Commenters noted that the Proposed RE Approach would require Kansas to have 8,885 GWh of renewable energy generation in 2030 but the Alternative RE Approach would require Kansas to have 50,905 GWh of renewable generation in 2030 which would require Kansas to generate over 8,000 GWh of renewable energy more in 2030 than generation from all energy producers in 2012. Commenters stated that the fact that the proposal does not provide for Kansas to receive credit for any wind energy sold to out of state customers under th e proposed rule would make the A lternative RE A pproach totally untenable. Commenters noted that requiring all additional renewable energy required to be utilized within Kansas' borders would provide the state with no means to prepare a plan that would not r esult in serious energy price impacts due to the installation of natural gas turbines to track the ten

- fold increase in wind development, reliability concerns due to the dramatic increase in wind power relative to total generation, and stranded assets due to the closure of retrofitted Kansas coal plants far beyond that envisioned by the Section 111(d) of the CAA.

Commenters stated that the Alternative RE Approach is flawed as it drastically overstates the renewable energy potential in the State of Kansas be cause the analysis performed fails to consider current land

- use constraints that will not accommodate the footprint of the potential wind generation. Commenters made multiple references to a document titled "U.S. Renewable Energy Technical Potentials: A GI S

- Analysis" and stated that upon review of the document and assessment of the land

- use constraints used in the model to develop the Alternative RE Approach, they felt that EPA's estimates are unrealistic and do not accurately account for all land
use const raints within Kansas. Commenters noted that EPA's analysis does not include any additional land use constraints such as areas that are habitat for species protected under the Endangered Species Act or those areas of Kansas that have increased development s crutiny for environmental, cultural or social reasons. For example, c ommenters noted that the document estimated that 89% of Kansas is available for onshore wind energy development and while this number did take into account the wind power potential and li mited number of federally

- owned properties in Kansas, it did not include other land use constraints such as the 2011 Tall Grass Heartland designation by Kansas Governor Sam Brownback. Commenters noted that EPA's analysis also did not consider land use cons traints associated with habitat used by federally protected species such as the whooping crane, or habitat associated with the "then proposed

- now threatened" lesser prairie chicken which, when considered, severely limits Kansas' available land. Commenters stated that these constraints preclude development in some of the most "wind rich" areas of Kansas, which include the eastern tall grass prairie and the western mixed grass prairie regions by making these areas financially, environmentally and politically unattractive for development.

Comment 7: Commenters provided commentary on EPA's RE results for Louisiana.76 Response 7: The final building block 3 methodology does not rely on state

- specific deployment estimates, but rather cost

- effective RE at an interc onnection level

. The basis for building block 3 target generation levels is the observed pattern of historical development for each of the BSER RE technologies

. The EPA addresses considerations related to the technical feasibility and associated grid integ ration costs of significant RE penetration in both the preamble (section V.E) and GHG Mitigation Measures TSD that support the final CPP.

The following are summaries of the specific public comments under this comment:

Commenters stated that the Alternative RE Approach shows that Louisiana has very little technical capabilities but noted that EPA sets a target that suggests considerable RE growth for Louisiana (184 percent), while the EPA's own alternative analysis shows that this is almost impossible. Commenters noted that the NREL document which EPA relied upon in its analysis contains a number of tables reflecting state's RE technical potential and shows that, with the exception of biomass, Louisiana is technically challenged in the area of RE development. Commenters noted that Louisiana's technical potential for wind is at the lowest end of the spectrum in the NREL document's maps, yet it has been lumped into a region with considerable wind energy resources and technical potentia l. Commenters stated that a similar trend is seen with Louisiana's solar capabilities.

Commenters believed that EPA's analysis confirms that Louisiana has already made excellent progress in realizing its RE potential, as Louisiana's projected RE potential makes it one of the top

- performing states in the country with regard to utilizing its available RE resources as identified by the NREL study. Commenters noted that in the future, Louisiana would only need to generate two percent of its electricity from ren ewable energy sources

-- a reduction compared to current levels

--- to maintain a level of performance similar to other high performing renewable energy states. Specifically, c ommenters noted that EPA suggests that Louisiana could reduce its total renewable en ergy generation from its 2012 level of 3,110 gigawatt

- hours to 2,503 gigawatt

hours by 2030 and still remain within EPA's expectation of good performance in utilizing renewable energy resources, as compared to the states overall renewable potential. Commen ters supported these conclusions and asked EPA to further confirm in its response to comments Louisiana's success in encouraging the appropriate and cost

- effective use of renewable energy

resources.

Comment 8: Commenters recommended that EPA give deferenc e to Minnesota's RPS as satisfying EPA's CPP Block 3 requirements.

Response 8: The final building block 3 methodology does not rely on state

- specific deployment estimates, but rather cost

- effective RE at an interconnection level

. The basis for building bl ock 3 target generation levels is the observed pattern of historical development for each of the BSER RE technologies

. The EPA addresses considerations related to the technical feasibility and associated grid integration costs of significant RE penetration in both the preamble (section V.E) and GHG Mitigation Measures TSD that support the final CPP.

The following are summaries of the specific public comments under this comment:77 Commenters recommended that EPA give deference to Minnesota's RPS as satisfying EPA's CPP Block 3 requirements by recognizing Minnesota's early action for renewable deployment as sufficient for satisfying EPA's CPP targets in response to EPAs request for comments on the imposition of an alternative RE value for state target setting. Commenters also suggested that EPA provide full credit for nuclear generation that has its licensing renewed to an overall 80 year facility life. Commenters noted that Minnesota renewable energy measures were established by the Minnesota legislature, giving consideration to feasible rates for renewable energy deployment and the ability of electric generating systems to assimilate the dispatch of intermittent renewable energy resources witho ut creating system reliability problems. Commenters stated that EPA should not implement its suggested expansion of renewable targets to "resource potential" in Minnesota, instead recognizing that the magnitude and pace of renewable energy deployment in Mi nnesota has already been exhaustively assessed and provided for in the RPS established by the Minnesota legislature and Minnesota regulators. Commenters stated Minnesota customers have paid for these renewable assets and other resource actions and should r eceive full credit.

Comment 9: Commenters stated that EPA's Alternative RE Approach for calculating Nebraska's RE goal is not realistic for several reasons

. Response 9: The final building block 3 methodology does not rely on state

- specific deployment estimates, but rather cost

- effective RE at an interconnection level

. The basis for building block 3 target generation levels is the observed pattern of historical development for each of the BSER RE technologies

. The EPA addresses considerations related to the technical feasibility and associated grid integration costs of significant RE penetration in both the preamble (section V.E) and GHG Mitigation Measures TSD that support the final CPP.

The following are summaries of the specific public comments under this comment:

Commenters stated that EPA's Alternative RE Approach for calculating Nebraska's RE goal is not realistic for several reasons: the alternative target would require an additional 4,000 MW of wind generation (assuming an annual capacity factor o f 50%) above Nebraska's initial Building Block 3 requirements in the regional approach, and although Nebraska law has provided for the export of wind generation since 2010 and many Nebraska wind projects have been proposed for export, none have actually be en developed over the past four years. Commenters noted that state law requires that any RE project greater than 80 MW to be approved based on documented need to serve Nebraska customers and that Nebraska currently has significant excess generation,
approv al for additional generation, whether wind or not, is problematic. Commenters stated that the Midwest region has a very good wind resource making it infeasible to export to neighboring states and that while limited wind exports from Kansas and Oklahoma to eastern states have utilized existing transmission facilities, the additional 4,000 MW of Nebraska wind generation contemplated by the proposed rule could not be exported on existing facilities and would require the addition of four 345 kV transmission lines approximately 800 miles average length to deliver to densely populated area s east of Nebraska. Commenters estimated that these new transmission lines would cost approximately $4 billion, at $1.25 million per mile, in addition to the $5 to $8 billion needed to build the 4,000 MW of wind generation.78 Commenters noted that states sur rounding Nebraska are also required to build significant amounts of wind generation and that these states will also be required to build significant transmission infrastructure deliver the wind energy to the densely populated areas in the eastern United St ates. Commenters stated that even if it could be determined quickly who would be financially responsible for this multi

- state, multi

- billion dollar investment, the ability to build multiple interstate transmission lines requiring the approval of state agen cies from multiple states would likely only happen with passage of federal legislation and that without such authority, potential investors are unlikely to fund any necessary transmission lines for the increased wind generation targets to make economic sen se.

Commenters stated that in 2012, they hired a water resources consultant to perform a feasibility level assessment of Nebraska's potential hydroelectric generation capacity and implementation potential at new and existing sites and based on this assess ment concluded that the Alternative RE Approach would be even more flawed if EPA considered generation from hydroelectric sources in determining Nebraska's RE state goal, as the additional generation required was not economically feasible.

Commenters state d that, without admitting that EPA has the authority to require "outside the fence" measures, a more workable approach for setting a RE target would be to consider resource availability, market constraints, reliability impacts, operational constraints, inf rastructure requirements, and electricity demand in establishing goals on a state

- by

- state basis where states could then work with the EPA to establish a final RE goal for that state.

Comment 10: Commenters do not support any efforts to use the CPP state renewable analysis to redefine RPS requirements for New Hampshire.

Response 10: The final building block 3 methodology does not rely on state

- specific deployment estimates, but rather cost

- effective RE at an interconnection level

. The basis for building bl ock 3 target generation levels is the observed pattern of historical development for each of the BSER RE technologies

. The EPA addresses considerations related to the technical feasibility and associated grid integration costs of significant RE penetration in both the preamble (section V.E) and GHG Mitigation Measures TSD that support the final CPP.

The following are summaries of the specific public comments under this comment:

Commenters stated that New Hampshire's renewable resource potential was specific ally evaluated by experts to establish the state's RPS goals which include a renewable resource target of 20 percent of total generation by 2020. Commenters noted that based on their translation of EPA's alternate state

- specific approach into the existing goal

- setting formula, New Hampshire's overall carbon intensity target would be 618 lb/MWh by 2030, which still requires investments in renewable resources, but is more appropriate given the status of the existing RPS goals and ACPs. Commenters stated that these alternate renewable targets are more closely aligned with existing RPS goals when ACPs are factored in as a compliance tool, but that they remain committed to the existing RPS requirements that are fully functioning in the Northeast State s. Commenters stated they do not support any efforts to use the CPP state renewable79 analysis to redefine RPS requirements, or that would affect the existing generation unit qualification requirements for each state's renewable standards.

Comment 11: Comme nters stated that while RE should not be used to set goals, New Jersey supports EPA's Alternative RE Approach

. Response 11: The final building block 3 methodology does not rely on state

- specific deployment estimates, but rather cost

- effective RE at an int erconnection level

. The basis for building block 3 target generation levels is the observed pattern of historical development for each of the BSER RE technologies

. The EPA addresses considerations related to the technical feasibility and associated grid in tegration costs of significant RE penetration in both the preamble (section V.E) and GHG Mitigation Measures TSD that support the final CPP.

The following are summaries of the specific public comments under this comment:

Commenters stated that while RE sho uld not be used to set goals, New Jersey supports EPA's Alternative RE Approach. Commenters noted that this approach is a more pragmatic method for determining state RE targets through the use of estimated technical and economic in

- state RE potential rathe r than RPS targets. Commenters noted that New Jersey has one of the nation's most aggressive RPS that supports renewable generation, not only within the state, but within the entire PJM region

. Commenters also noted that due to the limited technical and ec onomic instate potential, New Jersey expects that additional future RE required by Section 111(d) must be provided by renewable generation outside the state. Commenters stated that between 2006 and 2010, 75% of the RECs retired for New Jersey's RPS program have come from out

- of

- state renewables. Commenters pointed out that according to the National Renewable Energy Lab (NREL), RE technical potential identified in EPA's Alternative RE Approach TSD, New Jersey only represents 0.11% of the potential renewable generation in the nation, yet under EPA's proposed RE approach to BSER using RPS targets to infer RE potential, New Jersey is assumed to generate 2% of the total national renewable generation within the state. Commenters stated that this significant difference in BSER can be directly attributed to EPA's reliance on state RPS targets and the assumption that RPS compliance will come entirely from in

- state renewable generation. Commenters stated that EPA must therefore base N ew Jersey's goal on the Alternative RE Approach if RE is ultimately used in goal calculations.

Comment 12: Commenters stated that the conclusions reached for New Mexico under the Alternative RE Approach should be sufficiently striking to alert EPA to the flaws in its analysis.

Response 12: The final building block 3 methodology does not rely on state

- specific deployment estimates, but rather cost

- effective RE at an interconnection level

. The basis for building block 3 target generation levels is the obser ved pattern of historical development for each of the BSER RE technologies

. The EPA addresses considerations related to the technical feasibility and associated grid integration costs of significant RE penetration in both the preamble (section V.E) and GHG Mitigation Measures TSD that support the final CPP.80 The following are summaries of the specific public comments under this comment:

Commenters stated that the conclusions reached for New Mexico under the Alternative RE Approach should be sufficiently str iking to alert EPA to the flaws in its analysis. Commenters noted that New Mexico's goal would be revised to reflect a 500 percent increase renewable energy generation, essentially requiring 73 percent of all generation to come from renewable
energy resour ces

- as opposed to the 11 percent currently achieved, the 20 percent (at most) required by New Mexico's RPS, and the 21 percent expected under EPA's primary approach. Commenters stated that at 73 percent of total generation, the level of renewable energy
ge neration required under EPA's Alternative RE Approach, there would not be enough fossil fuel resources remaining in support of those renewable energy resources, which would present a severe reliability risk due to the variable nature of the generation they would provide.

Commenters additionally noted that other states such as Kansas, Idaho, and South Dakota are expected to generate more electricity from renewable sources in 2030 than they generated from all resources in 2012, including fossil fuels under E PA's Alternative RE Approach. Commenters also noted that, under the Alternative RE Approach, the Southeastern states are expected to reduce the percentage of electricity generated from renewable resources since six of the eight states in the region are expected to have lower renewable energy percentages in 2030 than in 2012. Commenters s tated that these results are unreasonable.

Comment 13: Commenters disagreed with an alternate RE target for North Carolina of 5% of 2012 generation

. Response 13: The final building block 3 methodology does not rely on state

- specific deployment estimates, but rather cost

- effective RE at an interconnection level

. The basis for building block 3 target generation levels is the observed pattern of historical development for each of the BSER RE technologies

. The EPA addresses considerations related to the techn ical feasibility and associated grid integration costs of significant RE penetration in both the preamble (section V.E) and GHG Mitigation Measures TSD that support the final CPP.

The following are summaries of the specific public comments under this comme nt:

Commenters noted that EPA has identified an alternate RE target for North Carolina of 5% of 2012 generation, and stated that this 5% target does not even represent North Carolina's commitments under its Renewable Energy Portfolio Standards, much less i ts full renewable potential.

Comment 14: Commenters believed EPA should consider modifying the methodology of the Alternative RE Approach to set a more accurate target that reflects what is actually achievable and cost

- effective for South Carolina

. Response 14: The final building block 3 methodology does not rely on state

- specific deployment estimates, but rather cost

- effective RE at an interconnection level

. The basis for building block 381 target generation levels is the observed pattern of historica l development for each of the BSER RE technologies

. The EPA addresses considerations related to the technical feasibility and associated grid integration costs of significant RE penetration in both the preamble (section V.E) and GHG Mitigation Measures TSD that support the final CPP.

The following are summaries of the specific public comments under this comment:

Commenters believed the targets established for South Carolina, a reduction of 772 lbs/MWh or 51% of carbon emissions, are achievable through new c lean and renewable energy and energy efficiency investments . H owever, commenters stated EPA should consider modifying the methodology of the Alternative RE Approach to set a more accurate target that reflects what is actually achievable and cost

- effective for South Carolina rather than estimate what is doable in the southeast region.

3.5.5 Regionalized approach

This section addresses comments on the target generation methodology for the alternative RE approach as it relates to a regionalized approach.

Com menters have raised a number of issues related to this subsection which are organized by topics (comments) below. Responses are provided for these topics.

Comment 1: Commenters stated that the Regionalized Approach referenced in EPA's NODA is preferable to the other alternative approaches that EPA has proposed.

Response 1: The resources and data provided in this comment were valuable in finalizing the building block 3 methodology, which is described in section V.E of the preamble and in the GHG Mitigation Measures TSD supporting the final CPP

. The following are summaries of the specific public comments under this comment:

Commenters stated they support EPA's inclusio n of renewable energy into the BSER as part of building block 3, but proposed revisions to the NODA Regionalized Renewable Energy Approach that would best ensure that the final plan correctly captures the achievable, cost

effective, and adequately demonstr ated growth of renewable energy. Commenters stated that while they strongly recommend that EPA strengthen the targets for renewable energy by adopting the NODA Regionalized Energy Approach for calculation of building block 3 of the BSER, subject to the mod ifications, if EPA declines to adopt that approach in the final rule, they recommend, in the alternative, that it adopt the state

- based technical and economic approach, as outlined in the TSD Alternative Renewable Energy Approach, subject to the modificati ons. Commenters also stated that if EPA fails to embrace either the preferred NODA approach or the TSD Alternative Renewable Energy Approach in the final rule, but instead adopts the Proposed RPS Approach for calculating building block 3, they propose nume rous revisions thereto to help ensure that it more accurately captures renewable energy potential.82 Commenters stated that the regionalized NODA technical and economic approach is vastly superior to the other proposed methods for calculating renewable energ y's contribution for state targets

. H owever, the commenters believed that EPA should make improvements to this approach to more accurately reflect the cost

- effective level of renewable energy deployment that can be achieved under the BSER, including the fo llowing modifications: (1) remove the "technical resource" step which imposes an "arbitrary cap", (2) rely on real

- world data on the cost of renewable technologies when quantifying which renewable sources are economic, (3) rely on DOE and NREL cost perform ance projections when projecting changes in the economics and performance of renewables though 2030, (4) model the cost of renewable curtailment that could occur at high renewable penetrations instead of imposing a cap on the percentage of variable renewab les that can be deployed in a state or region, (5) include changes to the generation mix and power system that are expected to occur between now and 2030 in the analysis of the economics of higher renewable penetrations, and (6) include planned transmissio n lines that will have been placed in service by 2020 in EPA's analysis.

Commenters stated that a regional approach to target setting more realistically and meaningfully captures renewable energy markets, especially since the resource will likely be utiliz ed across the region. Commenters stated that the economic potential for each state should include access to RE from states in the same market/transmission region and that EPA should allow states to use renewables and/or RECs they buy from out

- of

- state for compliance, to the extent that both the state buying renewables and/or RECs and the state originating them have compliance accounting systems, such that the generation and emissions reductions are not double counted. Commenters also stated that the REC tra cking requirements should be in harmony with existing tracking systems where processes are in place to prevent double counting both for generation tracked within projects and between projects and other REC tracking systems .

Commenters stated that EPA's re gional approach partially address concerns relating to transmission constraints and system integration costs to the extent that those constraints correspond with interstate transfers. Commenters noted that they support the regional approach because in a regional REC market, a state's opportunity to develop RE generation is far greater than the opportunities within a state. Commenters noted that because out

- of

- state renewables are allowed for compl iance, it is logical that the ability to access renewables available regionally should be a factor in a state's target. Commenters stated that a resource

- intensive state should not bear the entire burden for developing those resources, including hundreds o f millions of dollars of transmission interconnection costs and system

- wide transmission upgrades where the power will be utilized regionally and the emissions reductions will be experienced regionally as RE generation offsetting emissions located in other states with greater fossil generation but less renewable generation. Commenters praised the regional approach for providing a pathway to address some state's concerns with the original RPS proposal while eliminating the technical flaws in the Alternative RE Approach.

Commenters stated that they support a regional approach as long as it were implemented to make the rule more equitable by increasing the stringency of the goals of those states that have not significantly invested in RE to

- date and reducing t he goals of those states that have. Commenters noted that while the state

- by

- state alternative is appealing in part because it incorporates cost considerations into each state's RE target, a regional approach that mirrors the interstate nature of RE market s would better reflect the realities of the interconnected electricity grid and how83 individual states are choosing to increase their consumption of RE, e.g., by allowing load

- serving entities within the state to credit some portion of out

- of

- state RE gener ation or utilize "Renewable Energy Credits" ("RECs") towards compliance with state RPS goals. Commenters stated that at the very least, a regionalized approach should afford EPA the opportunity to apportion a greater share of the aggregate target to those states which have done relatively little to invest in RE generation capacity to

- date, either as producers or consumers of RE.

Commenters supported the regional approach, but thought that the idea was insufficiently developed in the NODA to draw a firm opi nion sufficient to form the basis for significant
comment. Commenters stated that if the Agency proceeds with this alternative, they believe the most credible structure would be one that reflects the operation of the electricity system itself. Commenters s tated that this would connect the generation of RE on that electrical system to the GHG emissions of the states in that region and thus, a grouping of states based on RTOs or NERC regions would seem most appropriate. Commenters also stated that if the Agen cy proceeds with the NODA Regional Approach, allocating the calculated regional RE generation proportionately to electricity sales seems fair, as this will be tied to the causal link of purchasing electricity.

Commenters stated that a regional approach mor e likely to secure support would allow states to retain their individual goals, but would provide for credit trading between the states as a compliance measure. Commenters supported EPA's final guidelines should keep either the state

only or regional appro ach. Commenters recommended that there should not be a requirement for a blended regional goal if multiple states prefer to essentially trade along the margins and in particular, EPA should also state that an acceptable regional approach option would allow multiple states to retain their individual goals, while providing for trading between states of credits representing tons of emissions or megawatt

- hours (MWh) of generation. Commenters noted that EPA or a third party could provide a credit tracking system to be used by states wishing to participate.

Commenters supported the Regional Approach proposed by EPA, but only after making particular critical technical revisions to the analysis. Commenters noted that they support the recommendations provided by Ren ewable Northwest in this regard. Commenters stated that EPA should adopt the NODA's regional interstate renewable energy market approach to give renewable energy credits value as a compliance tool and also that EPA should allow its economic potential anal ysis to determine economically reasonable renewable energy growth levels for each state.

Commenters stated that the Regionalized Approach may represent a viable option for determining state renewable energy targets, subject to an assessment of the details of the approach.

Commenters said, while the EPA's possible regional approaches to allocating renewable energy targets for the states might mitigate some of the disparate treatment of states under Block 3, the use of any regional approach does not address t he underlying problem with the EPA's proposed Block 3 approach of assuming one state's RPS can be used to assign renewable energy targets to other states. Commenters said, the discussion in the October 30 NODA (79 FR 34551) regarding alternate regional app roaches to setting state renewable energy targets is unclear as to exactly84 how these alternate approaches would affect any specific state. Commenters said, the EPA's proposed alternate regional approaches discussed in the NODA might mitigate the disparate impact of the growth rate approach in Block 3 to some degree by presumably raising the renewable energy targets of the other states that had lower renewable energy generation in 2012. Commenters said, however, these possible modified approaches do not addr ess the underlying problem with Block 3, i.e., the EPA is assuming that just because one state has set a renewable energy target that another state is capable of meeting that same target. Commenters said, the EPA has provided no evidence demonstrating the validity of this underlying assumption about the feasibility of Block 3.

Commenters stated, the EPA also appears to be contemplating combining the alternate renewable energy approach discussed in the Alternate RE Approach Technical Support Document with a regional approach (79 FR 64551). Commenters said, the EPA's alternate approach to determine state renewable energy targets is also flawed and using a regional approach to apportion the renewable energy generation will not address these flaws. Commenters s aid, additionally, the EPA suggests as an example criterion using the state's share of total electricity sales within the region to allocate renewable energy targets to individual states. Commenters said, using electricity sales as a criterion would be fun damentally flawed because the EPA used generation data, not electricity sales, in developing renewable energy targets. Commenters said, furthermore, electricity sales in a state do not demonstrate the feasibility for increased renewable energy in that stat e.

Comment 2: Commenters stated that EPA's proposed Regional RE Approach is not an appropriate measure to calculate state's RE targets because EPA's groupings lack a rational basis and have the potential to create disparities between states within a regio n.
Response 2: There are no groupings applied in the final methodology beyond the three interconnections

. Refer to sections V of the final rule preamble of the CPP fo r additional details

. The following are summaries of the specific public comments under this comment:

Commenters stated that EPA must establish RE goals based upon the unique potential for RE in each individual state because any other method will continue to lead to disparities between states and lead to goals that are not achievable. Commenters stated they do not believe that EPA can mandate a regional approach. Commenters stated that setting a goal in a manner that allocates regional RE to individual states without consideration for state

- specific RE potential will undoubtedly lead to the necessity for regional plans. Commenters noted that EPA suggested that the regional allocation approach may or may not apply to all RE generation in a state. [79 FR 64551] For example, c ommenters stated it may or may not include existing generation (b eyond 2012) or all types of RE generation (e.g., solar or wind)

. Commenters further stated that using a regional approach that does not take into consideration state

- specific potential and state

- specific in

- and out

- of

- state use of various RE sources will lead to states receiving disproportionate allocations compared to real world actuality which can be exacerbated over time as RE potential changes and more RE is developed. Commenters stated that the proposed rule essentially penalizes early adopters of RE and energy efficiency (EE) measures via more stringent goals,85 while at the same time ignoring the fact that most early RE and EE measures were based on what was most economically and technically feasible, as determined by that particular state. Commenters noted that it should not be the states obligation under comments regarding this proposal to provide recommendations to U.S. EPA and provide justification in lieu of U.S. EPA conducting the required analysis and proposing a specific approach. Commenters stated that EPA has obviously not done the proper research, nor expended the necessary effort to propose a technically sound, justified and vetted regulation and is now relying on states to provide fundamental feasibility analysis, research and recommendat ions for the final rule that should have been completed by U.S. EPA prior to proposing the rule.

Commenters stated that EPA's Regional Approach could effectively force states to rely upon generation resources outside their boundaries and, beyond their jur isdiction, making compliance subject to a multitude of factors outside of state control. Commenters also stated that utilizing a regional approach as applied to just this building block is highly arbitrary and while arguably all of the other building block s have regional attributes to their application, none of the other building blocks were examined or calculated within a similar regional context, presumably based on the fact that states are required to develop and implement these programs by statute. Comm enters also stated that any use of regions that do not correspond to small and distinct electric transmission control areas would ignore significant transmission constraints that must be addressed in order to accommodate regional renewable development. Com menters further noted that EPA has not provided any clear guidance within the proposal regarding how renewable credits could be treated within a rate

- based compliance approach given differences between the states' goals, nor would this approach be facilita ted by using a mass

- based compliance program
as out

- of

- state resources might not displace in

- state emissions. Commenters stated that the NODA provides no basis for informed comments absent clear guidance on interstate issues. Commenters stated that both EP A's proposed and Alternative RE A pproach are flawed and that applying a variation of that same flawed analysis to a broader region, and then using an unidentified process for allocating individual state responsibilities under this option, would be arbitrar y and capricious, and has no foundation in the materials placed in the record for this rulemaking.

Commenters stated the NODA indicates the potential for using a regional approach to set the NGCC floor and the RE (Building Blocks 2 and 3) targets. Commente rs stated the use of a regional approach is not appropriate for many reasons, not the least of which is a regional approach limits a state's flexibility. Commenters stated the regions identified do not match dispatch or market regions, creating seams, whic h introduce inefficiencies. Commenters stated that NODA does not consider the transmission needs necessary to move power across the region which introduces reliability, timing, and siting concerns and higher costs of electricity.

Commenters stated that EPA 's proposed alternate regional approaches discussed in the NODA might mitigate the disparate impact of the growth rate approach in Block 3 to some degree by presumably raising the renewable energy targets of the other states that had lower renewable
energy generation in 2012

. H owever, commenters said these possible modified approaches do not address the underlying problem with Block 3, i.e., the EPA is assuming that just because one state has set a renewable energy target that another state is capable of me eting that same target. Commenters also noted that EPA's alternate approach to determine state renewable energy86 targets is also flawed and using a regional approach to apportion the renewable energy generation will not address these flaws.

Commenters stat ed that EPA's use of a regions to establish RE requirements is significantly flawed and further regionalization may exacerbate these flaws. Commenters noted, for example, that EPA's South Central region, though geographically in the same area, contain few similarities regarding RE generation. Commenters noted that for this region specifically, EPA inappropriately used Kansas' RPS as a basis for establishing RE goals for the entire region and failed to account for Texas' RPS in setting the average RE target for the region. Commenters noted that EPA's request for comments is premature until an actual regional RE design is proposed, and then, commenters must be provided adequate time to review and comment on proposed substantive changes.

Commenters stated that the regional approach is impractical in the extreme. Commenters noted that Wyoming specifically has three sets of EGUs, none of whose operators is affiliated with distribution entities whose territories are coterminous with state boundaries, and two operat ors who do business in states that are not part of the West as EPA has defined it. Commenters noted that service territories that actually exist do not necessarily share the average characteristics of the states in which they are located. Commenters stated that it is unwise to assume that effective regional cooperation can emerge through a federal mandate, and particularly unwise to assume that regional entities can be established on EPA's ambitious schedule. Commenters believed that EPA should be more conc erned that it can frustrate regional cooperation by establishing goals that cannot be achieved, by predetermining an unpalatable structure, or by forcing relationships that would not otherwise be of mutual interest.

Commenters stated that if EPA insists on adopting Building Block 3, notwithstanding that doing so contravenes the CAA requirements that States establish standards of performance and apply them on a unit

- by

- unit basis, adding a regional component would further complicate its implementation and it is unclear how EPA would calculate regional targets. Commenters added that a regional approach does not take into account practical limitations, such as cross

- border transmission constraints. Commenters noted that state regulatory regimes for utilities ar e not made equal, and it is unclear how these different regulatory schemes will work harmoniously in implementing a region

- wide renewable energy plan. Commenters also stated that calculating renewable energy goals based on regional targets would exacerbate an already disproportionate
state

- by

- state structure.

Commenters stated that even if renewable resources across states in a region have similar technical potentials, the approach does not consider how these profiles may have dissimilar market potentials. Commenters stated that identical standards for groups of states clustered by their technical potentials are not necessarily reflective of relative compliance burdens, systems of cost recovery, and siting concerns. Commenters stated that i nadequately accoun ting for this cost information yields a method that may overlook opportunities for lower

- cost reductions which would be exploited using a more flexible approach with more precisely drawn regions.

Commenters stated that EPA's nomination of NREL to set RE ta rgets will inform state goals and thus overstep the authorities EPA retains under the law. Commenters noted that RE penetration has impacts on the grid that extend beyond just feasibility and that NERC has repeatedly made87 clear that the increased penetrati on of variable resources can and will strain the grid making the assessment of RE targets a decision that requires assessments beyond NREL's area of expertise. Commenters recommended that EPA allow states to set RE targets that would then inform the
state goal.

Commenters also noted that MISO analysis is indicating that EPA renewable targets have been set too stringent for the MISO states, due to high costs per ton CO2 reduction. Commenters therefore

, suggested that states should have the option of entering into collaborations that help develop mutually beneficial renewable deployment measures.

Commenters stated that the regional approach proposed in the NODA would depend on too many factors that are beyond the state's control, and therefore favored using a state

- by

- state determination based on the technical and market potential for renewable energy generation in that state.

Commenters stated that using a regional target to develop a state

- specific goal assumes that states will undertake regional or multi

- st ate compliance efforts and since EPA's proposal does
not require states to participate in multi

- state compliance plans, EPA cannot establish targets based on an assumption that multi

- state coordination will occur

.
Commenters stated that because the method ology used in the A lternative RE A pproach is flawed, any state

- by

- state allocati on of targets derived from the A lternative RE A pproach is also flawed and that EPA should refrain from conflating renewable energy data from different states altogether.

Comme nt 3: Commenters stated t he regionalized approach proposed in the NODA does not resolve many of the challenges identified in EPA's proposed and alternate approaches

. Response 3: In the final CPP, affected EGUs in one jurisdiction may procure incremental RE fro m another jurisdiction without a multi

- state compliance plan. S ee section s V.A.3, V.E.6, and VIII of the final rule preamble of the CPP for additional information

. The following are summaries of the specific public comments under this comment:

Comme nters stated concerns regarding the regional nature of electricity would remain an issue under the NODA approach. C ommenters stated EPA assumes that there will be regional compliance efforts and that states will be willing to engage in multi

- state planning; however, the amount of time required to develop a regional approach is likely longer than what is afforded under the proposed guidelines. Additionally, commenters stated, some states will have more of an incentive to participate in a regional approach than others. C ommenters stated that a state that is a net importer of RE will benefit from a regional approach that a llows it to take credit for RE built in another state, but serves load within the importer state. In contrast, c ommenters stated, a net RE exporting state has little to no incentive to allow renewables produced in the exporting state to be counted elsewher e. Commenters stated while the regionalized approach attempts to recognize the interstate nature of electricity, individual state goals create complications.88 Commenters stated i ndividual states may find themselves winners or losers depending on if they

are net importers or net exporters of renewable generation.

Comment 4: Commenters stated that a regional reapportionment of appropriately derived renewable generation targets may reduce disparities between state targets.

Response 4: The EPA agrees with this comment

. S ee sections V

. A and V.E of the final rule preamble of the CPP for additional information

. The following are summaries of the specific public comments under this comment:

Commenters stated that while the derivation of a renewable generation target may be appropriately based on in

- state technical and economic potential, the opportunities for developing renewable energy are regional in nature. Commenters stated that consistent with this observation, the NODA outlined an approach to computing Building Block Three state targets that, while derived using in

- state technical and economic potential analysis, proposes a subsequent regional reallocation of the renewable generation goals. Comment ers observed that a regional reapportionment of appropriately derived renewable generation targets may reduce disparities between state targets. Specifically, c ommenters stated that given that the electricity produced by renewable resources will be utilize d regionally, a resource

- intensive state should not bear the full burden of developing these resources. Commenters stated a regional reapportionment, especially one that aligns with the regional nature of the grid or the existing (or likely) renewable ener gy standard markets of the states may reduce this disparity. Commenters stated that furthermore, in some instances, the technical potential of a renewable resource may exceed what a host state can develop. Commenters also stated that at the same time, to t he extent that a state lacking substantial in

- state renewable resource potential is required to rely on out

- of

state renewable generation to comply with a regionalized target, such compliance will be subject to siting, permitting, and other regulatory acti ons of another jurisdiction that are beyond the state's ability to control. Commenters suggested EPA must provide clear guidance about how these contingencies affect compliance obligations.

Comment 5: Commenters stated that EPA's regionalized approach sho uld take into account interstate mechanisms as part of state targets.

Response 5: The details for procuring out

- of

- state incremental RE as part of a compliance demonstration are described in s ection s VA, V.E., and VIII of the final rule preamble of the CPP for EPA’s response to this comment.

The following are summaries of the specific public comments under this comment:

Commenters strongly encouraged EPA to adopt a system of attribution for renewable energy that supports rather than disrupts the robust interstate market in renewable energy and associated environmental attributes. Commenters noted that while an interstate approach to compliance does not necessitate an interstate approach to the "best system of emission reduction" (BSER), a89 carefully designed Regionalized Approach may alleviate stakeholder concerns that state targets do not match available compliance mechanisms, as ide ntified in the NODA.

Commenters stated that while EPA has suggested that an interstate approach to compliance will be acceptable in state plans and compliance calculations for renewable resources, it is important that these details be clarified to provide structured flexibility and eliminate uncertainty for affected EGUs. Commenters recommended that EPA support a variety of existing tracking systems to support demonstration of compliance and to ensure that there is no double

- counting of renewable energy cr edits

.
Commenters stated that they do not take a position on EPA's regionalized approach for setting the renewables target for states under building block 3 ; however, c ommenters noted that a regionalized approach would better align RE targets with the pro posal to allow the use of certain
out

- of

- state renewables for compliance, as the EPA noted as well.

Comment 6: Support and opposition for out

- of

- state RE credit.

Response 6: Building block 3 generation levels are premised on cost

- effective incremental RE at the interconnect level for a variety of reasons described in s ection V of the final rule preamble of the CPP. The EPA has provided clear guidance in section VIII of the fin al rule preamble of the CPP to dispel compliance uncertainty related to reliance on out

- of

- state RE resources.

The following are summaries of the specific public comments under this comment:

Commenters stated that while the regional approach provides flexi bility to recognize that renewables are best developed in optimal locations that may in fact be out

- of

- state and existing interstate REC markets, this option also poses significant complexity. Commenters noted that basing a renewable target based on techni cal potential does not factor in potential hurdles encountered in siting and development of greenfield sites, such as for wind and it does not consider or address the potential contentious issue of how the renewable requirements of the region ultimately ar e apportioned back to each state for goal

- setting. Commenters stated that
customers should receive the benefit of the utility investments they paid for, even if the investment is in another state and therefore, renewable and/or PPAs for zero carbon resourc es (i.e., wind or solar) should be considered toward the investing utility's home state goal

- setting and compliance. Commenters noted that this approach supports efficient compliance and recognizes that customers' utility rates funded these resources.

Com menters stated that EPA should revise Building Block 3's regional target methodology to exclude hydroelectric generation, EE savings, out

- of

- state renewable generation and state premium policy factors that are already captured by States' Renewable Energy S tandard ("RES").

Comment 7 : Commenters expressed support for a regional to RE goal setting

.90 Response 7 : The EPA agrees with this comment. S ee sections V .A and V.E of the final rule preamble of the CPP fo r additional information

. The following are summaries of the specific public comments under this comment:

Commenters stated a methodology based directly on renewable resource economics and demonstrated and future cost, such as the methodology set forth in the TSD, is a more appropriate measure of ac hievable and cost

- effective renewable energy than an approach based on historical state policies, such as the Proposed RPS Approach. Commenters stated in addition, the regionalized approach set forth in the NODA, is an improvement to the state

- by

- state TSD approach, as it correctly evaluates the achievable renewable potential of each state based on the quantity and cost of the regional renewable energy resource. Commenters stated, based on extensive historical experience of utilities procuring renewable ene rgy from other states in their region, through bundled RECs or other measures, this is a much more realistic metric of the quantity of renewable energy that is technically feasible, demonstrated, and cost

- effective for a particular state to procure for pur poses of Section 111(d) compliance. Commenters stated, therefore, consistent with the NODA approach, each state's emission reduction goals from renewable energy should be adjusted based on the total renewable energy potential available across a multi

- state region. In other words, commenters said a state's goal should be informed by the opportunity to develop out

- of

- state renewable resources as part of its state plan.

Commenters expressed concern regarding the renewable energy target

- setting component of bu ilding block 3, explaining that there is as a potential misalignment between estimating each state's target based on in

- state renewables while allowing use of out

- of

- state renewables for compliance with state goals, under the previously discussed methodolo gies. Commenters stated the NODA Regionalized Approach provides a third methodological option for renewable targets (beyond the RPS and alternative techno

- economic that were in the proposed rule) that would be based on a regionalized approach and remedy th is issue.

Commenters stated the NODA Regionalized Approach's target

- setting methodology takes into account interstate exchanges of renewables in the calculation of state goals and ; therefore, is better aligned with existing state renewable policies and pot ential claims on a given state's renewable generation by parties from other states, such as renewable energy certificates and power purchase agreements (PPAs). Commenters stated, specially, it correctly provides a direct evaluation, by EPA, of the technica lly and cost

- effectively recoverable level of renewable energy that each region can provide. Commenters stated this approach, if implemented as an improvement to the Alternative Renewable Energy Approach and subject to some modifications, is the preferred approach as it will accurately reflect the appropriate level of the technical feasibility and cost

- effectiveness of renewable energy generation, based on technology and market trends, which should be reflected in state targets. Commenters stated they think that better aligning goal

- setting to probable compliance approaches may mitigate some of these potential concerns.

Commenters stated that in light of EPA's acceptance of the feasibility of significant achievable levels of renewable energy in all regions, the c ommenters believe that EPA correctly proposes in the NODA to look at the renewable resources available in a region to inform state targets. Commenters stated such a regional approach would take into consideration the variation of91 renewable generation potential while accounting for the interconnected nature of the power system and the manner in which utilities have been purchasing renewable energy thus far.

Commenters stated a regional technical and market potential for renewable energy deployment would best reflect the real operation of the electricity system, relying on the flexibility made available and achieved through dispatching among multiple interconnected EGUs and other energy sources, including renewable energy, across state lines. Commenters s tated that a regional approach to quantification also gives a more complete picture of the use of renewable energy as well as the nature of carbon pollution. Commenters stated the global nature of the dispersion and impacts of carbon pollution supports a r egional approach, since the location of emissions or emission reductions does not affect the impact of such emissions. Commenters stated in recognition of the global nature of carbon emissions and the interstate nature of the electrical system, the NODA ri ghtly relies on a region

- by

- region assessment of renewable energy technical and market potential when determining the target for a particular state.

Commenters stated that s tates may differ in important ways, including in their mix of existing EGUs and pol icy priorities, but taking interstate renewable energy opportunities into account will create more achievable and equitable emission reduction goals. Commenters stated the very functioning of the electricity system itself relies on the inherent flexibility made available and achieved through dispatching between and among multiple EGUs and other energy resources, including renewable energy, interconnected across the broader bulk electric grid and over state lines. Commenters stated giving greater considerati on to interstate opportunities in the goal

setting process would allow also potential cost savings to be considered in assessing the reasonableness of the costs of state

- specific goals. Commenters stated that in other words, using regional evaluations allo ws the recognition of additional emission reduction opportunities from renewable energy that would be available at reasonable costs based on a more complete representation of the capabilities of existing infrastructure to accommodate shifts in generation

a mong EGUs in multiple states. Commenters stated, as such, if interstate renewable opportunities are accounted for, state

- specific goals can likely reduce more carbon, as they will be based on an assessment of the amount of emissions that can be reduced thr ough the application of a broader base for the BSER.

Commenters stated that interstate purchases of renewable energy are adequately demonstrated and in fact, are quite widespread, and their own analysis of publicly available PPA data finds that nearly 13,000 MW, or more than 20% of the nation's installed wind generatin g capacity, is currently under contract with a utility in a state other than the one in which the generation is located. Commenters noted this includes significant purchases of wind energy across relatively large distances, such as utilities in the Southea st purchasing and receiving physical delivery of wind energy from the Midwest, and utilities in California purchasing wind energy from the Pacific Northwest.

Commenters stated that in sum, their analysis shows that the Clean Power Plan would better take in to account the full value of renewable energy that is achievable and adequately demonstrated for deployment in states, while preserving reliability, ensuring reasonable costs, and delivering much deeper reductions in emissions, if it adopts in the final ru le based on the regionalized version of its Alternative Renewable Energy Approach set forth in the NODA, subject to the proposed modifications.92 Comment 8 : Commenters stated there is a mismatch between state

- based goals and inter

- state compliance.

Response 8 : The EPA disagrees with this comment

. The state goals that result from the application of the BSER are a function of the interconnection

- wide opportunities for deploying
cost

- effective RE

. A regional a pproach coupled with expressing building block 3 in terms of incremental RE corrects for the mismatch described by the commenter. Refer to s ection V A and V.E. of the final rule preamble of the CPP for EPA’s response to this comment.

The following are summaries of the specific public comments under this com ment:

Commenters stated that EPA failed to explain how determining renewable energy potential on a regional basis will somehow resolve the mismatch between state

- based goals and inter

- state compliance where the regional renewable potential would still be a llocated on a state

- by

- state basis and believed that the most appropriate way to resolve the "misalignment" between establishing state

- specific targets and allowing out

- of

- state renewables for compliance is to simply disallow the use of out

- of

- state renewa bles for compliance, and asked EPA to adopt that approach. Commenters stated that allowing states to rely on out

- of

- state resources for compliance purposes would remain inconsistent with the manner in which the goals were set.

Commenters stated that implementing a regional approach to renewable energy will also be difficult in the Southwest and West, where there are no regional transmission operators or independent system operators to help coordinate the integration and support of new vari able renewable energy generation resources across non

- jurisdictional generators. Commenters further stated that even if EPA's regional approach could resolve the misalignment between targets and compliance, it would only do so if states were limited to usi ng renewable resources within their own region for compliance purposes, and not any renewable resources from other regions, but EPA has not indicated that it would impose such a restriction.

Commenters added that EPA failed to provide stakeholders with su fficient detail in regard to the Regional Approach, as the discussion of this approach spanned less than one page in the NODA. Commenters noted specifically that EPA provided no indication as to whether it prefers allocating a region's renewable potential among states in a region on the basis of generation, sales or any other metric. Commenters also stated that EPA failed to provide sufficient detail regarding how it plans to divide the country into regions, or address the fact that many states currently re ly on renewable energy credits from resources located not just in different states, but in entirely different regions as well.

Comment 9 : Commenters supported a methodology based on the cost

- effective potential for RE on a regional scale.

Response 9 : The EPA disagrees with this comment and believes using affected EGU generation as the basis for apportioning building block 3 generation is more consistent with the BSER

. See section V A. And V.E. of the final rule preamble of the CPP for additional information

.93 The following are summaries of the specific public comments under this comment:

Commenters stated they support a methodology using cost

- effective potential for renewable energy (RE) development on a regional scale to set emission reduction goals under building block three

. C ommenters stated that the best way to assign states' "share" of their regional RE potential is based on how much electric load is served by that state. C ommenters believed that this framework best represents states' abilities to acc ommodate a share of the increase in the region's RE and gives incentives to states to pursue policies that encourage the use of RE. C ommenters noted that this framework also most closely matches the way states will utilize renewable energy to demonstrate c ompliance with the standard and is consistent with how state RPS are handled. Commenters noted that due to variations in economic, operating, and climatic conditions, tying such sales to one year may be distortionary, and recommended allowing consideration of additional years with justification provided by states.

Comment 10 : Commenters opposed use of generation data in developed RE targets.

Response 10 : The EPA agrees with this comment and has used affected EGU generation as the basis for apportioning bu ilding block 3 generation levels

. S ee section V A. and V.E. of the final rule preamble of the CPP fo r additional information

. The following are summaries of the specific public comments under this comment:

Commenters did not agree with EPA's suggested use of a state's share of total electricity sales within the region to allocate RE targets to individual states and stated that using electricity sales as a criterion would be fundamentally flawed because the EPA used gen eration data, not electricity sales, in developing renewable energy targets. Commenters noted that electricity sales in a state also do not demonstrate the feasibility for increased renewable energy in that state.

Comment 11 : Commenters proposed changes to EPA's defined regions.

Response 11 : The building block 3 regions are the interconnections; consequently, all Eastern Interconnection resources are grouped with all Eastern Interconnection affected EGUs

. See section s V .A and V.E. of the final rule preamb le of the CPP for additional information.

The following are summaries of the specific public comments under this comment:

Commenters stated that for the most part, they think that grouping of states reflects the manner in which they are currently involve d in interstate renewable exchanges and are likely to be so in the future. However, c ommenters stated they believe adjustments to the regions, or allowances for renewable energy resources to serve another region, are necessary to maintain consistency with existing RPS requirements and accurately represent current renewable energy exchanges.

Commenters stated that the potential for all types of RE should be aggregated to form regional RE totals prior to allocation back to individual states.94 Comment 12 : Com menters renewable resource in reasonable proximity to the PJM footprint should be counted towards the economic resource available to PJM states.

Response 12 : The building block 3 regions are the interconnections; consequently, all Eastern Interconnection r esources are grouped with all Eastern Interconnection affected EGUs

. See section s V .A and V.E. of the final rule preamble of the CPP for additional information.

The following are summaries of the specific public comments under this comment:

Commenters stated Illinois, or at least the renewable resources it has access to, should be counted as available to the PJM states (the East Central region in the grouping included in EPA's June 2 release) for purposes of setting the building block 3 standard under t he regionalized NODA approach. Commenters stated that given that the northern Illinois utility Commonwealth Edison's service territory is in PJM, and that this service territory accounts for around half of the total wind generation in PJM, this change is e ssential to accurately represent which renewable resources are available to which regions. Commenters stated this change is critical as many existing state RPS policies in the PJM states allow renewable energy delivered to anywhere in PJM's footprint to co unt for purposes of RPS compliance. Commenters stated because many states may choose to comply with Section 111(d) by simply using or increasing their existing RPS requirements while maintaining existing RPS rules for renewable eligibility and deliverabili ty, the BSER should reflect the reality of those existing RPS provisions. Moreover, c ommenters stated renewable resource areas in reasonable proximity to the PJM footprint should be counted towards the economic resource available to PJM states, reflecting the reality that renewable developers have frequently chosen to use generator tie lines and grid upgrades of dozens or even hundreds of miles to access desirable markets, including PJM's RPS markets.

Commenters provided a map which shows that the PJM inte rconnection queue contains many proposed wind projects extending well into central Illinois. Commenters stated that these projects have applied for interconnection to the PJM power system, and therefore their output would be eligible for meeting RPS requir ements in many PJM states. Commenters provided additional detailed information on the PJM and MISO interconnection queues for proposed wind projects in Illinois. Commenters also stated, the geographic boundaries of the ComEd region in IPM's modeling should be validated against the actual PJM footprint map, which appears to show a significantly larger area.

Comment 13 : Commenters renewable resource in reasonable proximity to the PJM footprint should be counted towards the economic resource available to PJM states.
Response 13 : The building block 3 regions are the interconnections; consequently, all Eastern Interconnection resources are grouped with all Eastern Interconnection affected EGUs

. See section V A and V.E of the final rule preamble of the CPP for add itional information.

The following are summaries of the specific public comments under this comment:95 Commenters stated some or all of the renewable resources in Indiana and Michigan should also be counted as available to PJM states (EPA's East Central region) for purposes of setting the building block 3 standard under the NODA Regionalized Renewable Energy Approach, reflecting that a significant share of the wind resources in those states are located within or near the PJM footprint. Commenters referenced a map showing a large number of proposed wind projects in Indiana, and several in southern Michigan, that have ap plied for interconnection to the PJM power system. Commenters provided additional detailed information on the PJM and MISO interconnection queues for proposed wind projects in Indiana. Commenters stated the load/generation of Indiana and Michigan, or at le ast the vast majority of it, should remain in MISO to reflect that the vast majority of the load/generation in those states is in the MISO footprint.

Comment 14 : Commenters renewable resource in reasonable proximity to the PJM footprint should be counted towards the economic resource available to PJM states.

Response 14 : The building block 3 regions are the interconnections; consequently, all Eastern Interconnection resources are grouped with all Eastern Interconnection affected EGUs

. See section s V .A and V.E of the final rule preamble of the CPP for additional information.

The following are summaries of the specific public comments under this comment:

Commenters stated North Carolina, or at least the load/generation that is in the PJM footprint and the renewable resources that are in and near the PJM footprint, should also be counted as being in PJM (EPA's East Central region). Commenters provided a map showing th ere is significant renewable development planned for the PJM portion of North Carolina, and output from these resources would be eligible for compliance with RPS requirements in many PJM states. Commenters provided additional detailed information on the PJ M interconnection queues for proposed wind projects in North Carolina.

Comment 15 1 4 : Commenters stated Kentucky's load/generation and renewable resources should be grouped with EPA's North Central region.

Response 15 1 4 : The building block 3 regions are the interconnections; consequently, all Eastern Interconnection resources are grouped with all Eastern Interconnection affected EGUs

. S ee section s V .A and V.E of the final rule preamble of the CPP fo r additional information

.
Commenters stated Kentucky's load/generation and renewable resources should be grouped with MISO (EPA's North Central region). Commenters stated, in the alternative, Kentucky's load/generation could be pro

- rata apportioned, with the load/generation for th e portion of Kentucky in the MISO footprint allocated to the North Central region and the load/generation in the PJM footprint allocated to the East Central region. Commenters stated it should be relatively easy to adjust, on a load

- or generation

- weighted basis, the share of a state's load or generation that falls in each region for purposes of setting the renewable energy component of the building block 3 targets.96 Comment 1 6 1 5 : Commenters stated wind energy generation from MISO and SPP should be accounted for in the regional or state calculations of economically available RE.

Response 16 1 5 : The building block 3 methodology relies on the ability of affected EGUs to procure incremental RE within the interconnection

. Refer to s e ction s V .A and V.E of the final rule preamble of the CPP for additional information

. The following are summaries of the specific public comments under this comment:

Commenters stated the adequately demonstrated ability of Southeastern utilities to import wind
energy gener ation from MISO and SPP should be accounted for in the regional or state calculations of economically available renewable energy resources. Commenters stated this could be accomplished by grouping at least some Southeastern states in with MISO (North Centr al) or SPP (South Central), or making some share of the economically viable renewable energy resources in MISO and SPP available for meeting the Section 111(d) compliance needs of the Southeast. Commenters stated this would accurately reflect the fact that Southern Company and TVA are purchasing large amounts of wind energy, with physical delivery, from SPP and MISO. Commenters suggested EPA should look at existing and new transmission into the Southeast and give at least some of those states a target that incorporates transmission

- delivered renewable energy.

Commenters stated it is also important for EPA's modeling to include the opportunity for new high

- voltage direct current (HVDC) transmission lines, which have different cost and performance characteris tics than AC transmission. Commenters stated this includes the capabilities of DC transmission voltage source converters to provide a variety of ancillary services, including rapid adjustments to real power output, allowing variability to be exported to th e receiving region.

Commenters also stated the ability to use HVDC to provide capacity and reserve sharing should also be accounted for. Commenters stated a number of studies have identified how HVDC transmission lines can play an important role in achiev ing cost

- effective reductions of carbon emissions by allowing delivery of low

- cost renewable energy. Commenters provided information on a DOE funded Eastern Interconnection Planning Collaborative (EIPC), noting the results show that some economic potential for inter

- regional transfer using new HVDC lines should be accounted for in setting state targets under building block 3

. Commenters also stated that several new inter

- regional HVDC transmission lines, similar in capacity and rationale to those found in E IPC results, are well under development and expected to be in service by 2018. Commenters stated EPA should include these new HVDC projects in its IPM modeling by adding the expected incremental transmission capacity between the US Model Regions in EPA Bas e Case v.5.13. Commenters stated because IPM uses wheeling charges to represent a real

- time cost in order to determine the optimal path for energy transfer, the wheeling charge would be zero for these lines as the wind generation would be directly connecte d to these lines and would not have another path for delivery.97 Comment 17 1 6 : Commenters stated the ERCOT IPM region does not include wind resources in the Texas Panhandle.

Response 17 1 6 : The RE resource potential in IPM is desc ribed in terms of geographic location, rather than ultimate availability.

The following are summaries of the specific public comments under this comment:

Commenters stated the ERCOT IPM region incorrectly does not appear to include wind resources in the Texas Panhandle. Commenters su ggested EPA should ensure that a large share if not all of the Texas Panhandle wind resources are available to the ERCOT IPM zone, in addition to being available to SPP West, to properly reflect that both RTOs have transmission facilities that allow signif icant deliverability of wind generation from the Texas Panhandle. Commenters stated if EPA is absolutely unable to model both regions having access to those wind resources, EPA should either split the Texas Panhandle wind resources between the two regions or allocate them all to ERCOT, reflecting that with the completion of the CREZ lines ERCOT now has larger deliverability of those wind resources than SPP.

Comment 18 1 7 : Commenters stated there are inaccuracies in the IPM assumptions table.

Re sponse 18 1 7 : The EPA is constantly reevaluating interregional transmission assumptions for inclusion in IPM; however, no change was made at this time to the modeling that supports the final CPP.

The following are summaries of the specific public comments under this co mment:

Commenters stated that EPA should check the regional transfer limits listed in Table 3.4 on pages 6

- 12 of Chapter 3 of the IPM documentation to verify that the MW transfer limits are an accurate reflection of current reality, as well as the increase d transfer limits that will be enabled by new transmission, as many appear to be lower than indicated in documentation provided by regional reliability entities. Commenters noted that for many of the ties in the Western Interconnection, documentation of cu rrent transfer limits can be obtained from the WECC Path Rating Catalog which indicates that most ties in the Western Interconnection have a significantly higher transfer capability than is assumed in the IPM modeling. Commenters noted that they

were unabl e to find access to a similar comprehensive listing of current transfer limits for the Eastern Interconnection and ERCOT, though based on the number and magnitude of concerns identified in WECC

. Commenters suspected that there are similar inaccuracies in t hose lists as well. Commenters provided a list of 19 discrepancies they found between the WECC Path Rating Catalog and the IPM assumptions table.

Comment 19 1 8 : Commenters suggested the EPA base RE targets on technical potential.98 Response 19 1 8 : The final building block 3 methodology is premised on historical deployment of RE capacity rather than modeling projections

. Refer to section s V .A and V.E of the final rule preamble of the CPP for additional information.

The following are summaries of the specific public comments under this comment:

Commenters stated the regional approach to renewables may still group states together that have widely varying renewable resources potentials, and suggested that EPA base renewable targets on technical potential throttl ed by an avoided cost threshold, consistent with utility planning.

Comment 20 19 : Commenters expressed concern that the alternative approach would result in unrealistic rate targets.

Response 20 19 : The final building block 3 methodology is premised on historical deployment of RE capacity rather than modeling projections

. Refer to s e ction s V .A and V.E of the final rule preamble of the CPP fo r additional information

. The following are summaries of the s pecific public comments under this comment:

Commenters stated that the NODA describes comments EPA has received that propose calculating building blocks three and four by assuming incremental renewable energy and energy efficiency would displace existing l evels of fossil generation rather than growth in demand for fossil generation. Commenters stated they do not support this approach, stating that this alternative method would result in rate targets with unrealistic compliance expectations. Commenters provi ded the example that a state could have a zero or even a negative rate

- based target, and yet serve load with a substantial amount of fossil

- fuel generation. Thus, c ommenters stated, the approach to calculating building blocks three and four in EPA's June 2 , 2014 proposal of the Clean Power Plan appropriately accounts for incremental RE and energy efficiency.

Comment 21 2 0 : Commenters stated that they support the use of a regional approach if EPA cannot fix and implement an approach based on the technical and economic potential for each
state.

Response 21 2 0 : The EPA adopted a regional approach to building block 3 as it was most consistent with the BSER

. S ee section s V A and V.E of the final rule preamble of the CPP for EPA’s response to this comment.

The following are summaries of the specific public comments under this comment:

Commenters stated if EPA is unable to address the issues with the current technical and economic potential approach, use the regional approach proposed in the NODA in which the existing targets from the Alternative RE Approach TSD are aggregated by region and reassigned bas ed on retail sales. Commenters stated concerns about the methodology used to assign renewable energy targets to states that are dominated by hydropower in the technical and99 economic potential approach, and provided suggestions for strategies to either fix or compensate for those issues. Commenters stated, however, in recognition of the fact that EPA may simply not have the time or resources to address those issues and provide solutions in a timely fashion, the c ommenters would recommend using the "regional potential" approach outlined in the NODA. Specifically, c ommenters recommended using the same regional grouping as with the RPS

- based regional approach (i.e., the WECC footprint) and assigning the total renewable energy potential based on the proportion of baseline retail sales for each state. Commenters noted that the IPM modeling done for the technical and economic potential approach is regional in nature already and based on WECC classifications for the west. Therefore, c ommenters stated, this approach i s more consistent in terms of using the data that provides the foundation for the assigned targets. Also, c ommenters noted that the renewable energy target would be bounded by the requirement above that no state is assumed in the target setting process to be required to generate more than 100 percent of its baseline generation from zero emission sources.

Commenters stated that to the extent that EPA establishes a federally

- enforced RE target for Connecticut, compliance with which requires Connecticut to de velop resources in other states,

c ommenters are concerned about the feasibility of complying with such a mandate. Commenters noted that Connecticut has an ambitious RPS target, established under state authority, with expectations of significant development of out

- of

- state RE. Commenters also noted that Connecticut has very limited RE generation potential in

- state and does not have control over the permitting, siting, and regulation of facilities located outside its borders. Commenters therefore stated, notw ithstanding the inherent ability to overcompensate in some building blocks to make up for deficiencies in others, given state sovereignty issues, a mandated requirement to build out

of

- state renewables is not appropriate. Commenters stated that they prefer a method that sets in

state RE goals based on in

- state technical and economic potential; however, should EPA determine that such a method cannot be implemented, then the c ommenters strongly prefer an approach based on regionalized technical and economic p otential over the proposed RPS approach

.

Comment 22 2 1 : Commenters stated the EPA should credit excess RE based on the regional steam fossil emissions rate.

Response 22 2 1 : The final building block 3 produces incremental RE generation levels at the interconnection

- level rather than the state

- level

. All qualifying RE is credited, under rate

- based compliance, against the standard applied to the affected EGU that procured the incremental RE

. For additional information regarding how affected EGUs demonst rate compliance, refer to section VIII of the preamble that supports the final CPP.

The following are summaries of the specific public comments under this comment:

Commenters stated that in the case where a states' incremental RE and EE exceeds historical fossil steam generation levels, EPA should credit this excess renewable energy based on the regional steam fossil emissions rate. Commenters stated that the regional average fossil steam generator emissions rate will accurately reflect the amount of emissi ons savings that would be produced by adding renewable energy, given how renewable resources displace fossil generation100 resources throughout the region due to the interconnected nature of the power system. Commenters stated that if all regional steam fossi l generation is exhausted, renewable generation should be credited at the region's natural gas combined cycle (NGCC) emissions rate.

Comment 2 3 2 2 : Commenters stated the EPA should adopt a regional version of the Alternative RE Approach and recommended the same approach for power plants in Indian Country.

Response 2 3 2 2 : The EPA agrees with this comment

. Affected EGUs in Indian Country are subject to the same interconnection

- level requirements as other affected EGUs

. S ee sections V .A and V.E of the final rule preamble of the CPP for EPA’s response to this comment.

The following are summaries of the specific public comments under this comment:

Commenters recommended that EPA adopt a regional version of the Alternative RE Approach as described in the NODA, and also recommended that EPA follow the same approach for power plants in Indian Country by increasing the size of the target to reflect the appropriate emissions

weighted share of the renewable energy available in the t ransmission or market region. Commenters stated that there is no justification for adopting a unique A lternative RE A pproach which assigns a lower renewable generation target to these facilities. Commenters stated that for the power plants in U.S. territor ies, the targets should reflect the potential renewable energy resources that can be developed at reasonable cost (based on updated cost data) in those territories.

3.5.6 Other

This section addresses comments on the target generation methodology for the a lternative RE approach including comments suggesting other approaches.

Commenters have raised a number of issues related to this subsection which are organized by topics (comments) below. Responses are provided for these topics.

C omment 1 : Commenters urged EPA to consider a proposal developed by the Union of Concerned Scientists which they believe would more fairly calculate renewable development goals for U.S. tribes and territories.

Response 1 : The resources and data provided in this comment were val uable in finalizing the building block 3 methodology, which is described in section V.E. of the preamble and in the GHG Mitigation Measures TSD

. The following are summaries of the specific public comments under this comment:101 Commenters stated that this ap proach would expect each state to sustain the same level of renewable growth starting in 2017 that it achieved in the five

- year period from 2009 to 2013, with a floor of 1.0 percent annual growth and a ceiling of 1.5 percent annual growth (and a cumulative ceiling of 40 percent renewable penetration). Commenters noted that, unlike EPA's approach, these growth rates refer not to the percentage increase in renewable megawatt hours over the previous year, but to the percentage of the state's total electricity sales that come from renewable resources. Commenters stated that they believe this approach would be fair in its application to tribal nations and Guam, which would begin at a cumulative RE penetration of 1.0 percent in 2017 (assuming they would all be sta rting at zero) and would achieve 13.0 percent by 2029. Commenters added that given the strength of the renewable resources in these jurisdictions, and the fact that the actual electricity sales on tribal lands are only a small percentage of total generatio n, they should have little difficulty achieving the emission reductions associated with this approach. Commenters noted that in Puerto Rico, the UCS approach would yield a benchmark that actually falls below the territory's RPS for 2020, which would requir e 15 percent of electricity sales to be generated from renewable resources. Commenters stated that because EPA's plan must not fall short of a region's own self

- imposed obligations, EPA needs to ensure that the Building Block 3 reductions for Puerto Rico a re, at a minimum, as stringent as its RPS obligations.

C omment 2 : Commenters suggested an alternative RE approach.

Response 2 : The resources and data provided in this comment were valuable in finalizing the building block 3 methodology, which is described in section V.E. of the preamble and in the GHG Mitigation Measures TSD

. The following are summaries of the specific public comments under this comment:

Commenters presented a different A ltern ative RE A pproach which they call the 'UCS Demonstrated Growth Approach' that builds on both of EPA's approaches by incorporating the following core components: setting a national RE growth rate benchmark based on demonstrated growth from 2009 to 2013, assuming full compliance with current state RES policies (as set b y law) that require certain percentages of electricity to come from renewable sources, and accounting for actual and expected RE growth between 2013 and 2017. Commenters noted that they assumed state

- level RE targets begin in 2017, the proposed start date for state compliance plans, and ramp up through 2030.

Commenters stated that they used EIA's actual renewable generation data from 2013 (the EPA's approach uses 2012 data) and add projected generation from wind and utility

- scale solar projects known to b e under construction through 2016. Commenters stated that t o calculate RE targets for 2030, employed a four

- step approach:

1. First, c ommenters used EIA data to calculate each state's average RE growth rate from 2009

- 2013 and found that, on average, states increased their renewable share of electricity sales by 1 percent annually. Commenters used this growth rate as their national benchmark since they believed the 2009

- 2013 period accounts for the recent rapid growth102 in wind and solar technologies, eases fluctuations in development due to uncertainty around federal tax credit expirations and extensions, and captures much of the historic development spurred by state RES policies. Commenters noted that 11 of the 15 leading states that have achieved growth rates at or above the national benchmark from 2009 to 2013 have also achieved a 1 percent or higher average annual growth rate over a 10

- year period from 2004 to 2013.

2. For states below the 1 percent national benchmark, c ommenters assumed that they gradually ramp up to that rate from 2017 to 2020. Commenters stated that this period serves as an opportunity for states that have not been as active in de ploying new renewable energy sources to catch up to the national benchmark. Commenters assumed that RE will grow after 2020 in these states at an annual rate of 1 percent of total sales through 2030.

3. For the 15 leading states among those that have been de ploying renewable energy at or above the national benchmark, c ommenters increased their respective renewable energy targets from 2017 to 2030 at each state's average annual growth rate during the five

- year benchmark period, up to a maximum of 1.5 percent p er year. Commenters viewed this as a reasonable, sustainable limit which is supported by the fact that seven states have achieved annual average growth rates of 1.5 percent or more over a 10

- year period from 2004 to 2013 based on EIA data.

4. Finally, to acco unt for full compliance with mandatory state RES laws, c ommenters assumed that states achieve the greater of two measures: the generation projected by their growth rate approach; or the level needed to meet states' respective RES targets for each year from 2017 to 2030, as projected by the Department of Energy's Lawrence Berkeley National Laboratory

. Commenters also capped the total share of renewable generation for any state at 40 percent of total state electricity sales to ensure reasonably achievable

ren ewable energy penetration rates during the compliance period. Commenters noted that this level has been shown to be achievable by grid operators, utilities, and government agencies.

Commenters noted that their proposal leads to stronger RE targets for stat es than those proposed by EPA and if all states meet these targets, the nation's electricity coming from RE in 2020 would double compared to EPA's proposal from 7 percent of total sales to 14 percent. Commenters stated that under EPA's approach, many of th e RE targets for Midwestern and Western states reflect little, if any, more renewable energy than what they have already achieved. Commenters noted that their approach encompasses the reasonable expectation that these states will continue to grow at rates similar to what they are currently demonstrating. Commenters provided a table of state and regional renewable energy generation under the 'Demonstrated Growth Approach' from 2017

- 2030 in Appendix 2 of their comment.

Commenters also noted that their approac h's higher levels are RE are technically feasible because their approach requires only a small fraction of the vast RE resources that are technically available and, unlike EPA's approach, includes offshore wind potential in the U.S. Commenters stated that given the status of these projects, and the likelihood that states will include them in103 their state compliance plans, they recommend that the EPA consider including a contribution from offshore wind as a potential BSER option over time.

Commenters asserted that their approach is more affordable and will result in greater emission reductions than either of EPA's proposed approaches. Using NREL's ReEDS mode, Commenters analyzed the impacts on CO2 emissions, electricity and natural gas prices, and the electric ity generation mix of achieving the state renewable energy targets under the UCS approach compared with business as usual, focusing on the renewable energy building block. Commenters stated that under their approach, total CO2 reductions achieved by the Cl ean Power Plan could increase from 30 percent below 2005 levels to nearly 40 percent. Commenters also noted that the ReEDS modeling showed that the additional RE generation would displace mostly natural gas.

Commenters stated that their approach is also a ffordable as consumer electricity prices were a maximum of 0.3 percent higher per year than BAU through 2030, which equates to an 18 cent increase in monthly electricity billing for a typical household. Commenters also stated that under their approach, the national average price of natural gas delivered to the electricity sector would be 9 percent lower than business as usual by 2030 and at the regional level, average consumer electricity prices would range from a 3.7 percent reduction to a 3.4 percent incr ease, while power sector natural gas price reductions would range from 8 percent to 17 percent by 2030. Commenters also found that the incremental cost of increasing renewables under their proposal was at or below EPA's $30/MWh assuming national trading of RECs.

Commenters noted that their methodology is technology neutral and there could be significant regional variation in the actual renewable energy resources deployed as the state policies implemented to help achieve compliance with the Rule could also impact what renewable resources get developed. Commenters also noted that their approach is robust across a range of assumptions, as they analyzed sensitivities related to key parameters in their approach (e.g. increasing the growth rate, including a lower electricity sales cap, removing the cap from share of electricity sales and/or state annual RE growth rate) and found that it is robust to these changes.

Commenters recommended that EPA adopt the RE projection methodology proposed by the Union of Concerne d Scientists (UCS) in the report Strengthening the EPA's Clean Power Plan because it uses actual, state

- specific data and assumptions. Commenters noted that this methodology is similar to EPA's alternative method but is superior because the UCS method uses actual development data. Commenters proceeded to detail how the UCS approach accurately represented RE potential in Idaho. Commenters further noted that the UCS proposal has important caps on total RE development to ensure the presumed levels are reasonab le.

Comment 3 : Commenters suggest an approach that considers regional differences in RE tech nology market penetration rates and use 2013 EIA data.

Response 3 : See section V.A. of the final rule preamble of the CPP for EPA’s response to this
comment.

The following are summaries of the specific public comments under this comment:104 Commenters proposed another option for improving EPA's Alternative RE Approach which differs from EPA's approach in that it primarily considers regional differences in renewable

en ergy technology market penetration rates, and assumes states with RES policies achieve full compliance with these laws. Commenters added that this approach also utilizes the most current renewable generation data available from EIA for 2013 (instead of 201 2), including generation from distributed solar PV, which the EPA did not include.

To calculate 2030 state RE targets under this approach, c ommenters divided 2013 renewable generation by NREL's estimated resource technical potential for the following tech nologies: utility scale PV, distributed PV, concentrating solar power (CSP), onshore wind, and conventional geothermal and then used these percentages to establish national and regional technology benchmarks. Commenters noted that due to the low number of states currently generating power with geothermal and CSP, the benchmarks for these technologies were based on a smaller subset of states, 6 states and 3 states, respectively.

Commenters then calculated regional benchmark penetration rates based on the ave rage of the top three performing states within each of the regions as defined by the EPA to account for the variation in resource potential and utilization across different areas of the country. Commenters then calculated 2030 RE targets by multiplying eac h state's technical potential for each technology by the greater of either the national or regional benchmark for that technology. In addition to the aforementioned technologies, Commenters also included existing biopower and new hydropower generation, usi ng the EPA's methodology for assessing the potential contribution of these technologies. Commenters stated that the potential for new hydropower in 2030 was estimated by subtracting 2013 hydro generation from NREL's estimate of hydropower potential for eac h state and that biopower and hydropower generation were added to the benchmarked technologies in order to calculate combined 2030 renewable energy targets.

Commenters noted that the share of each state's RE generation is capped at 40 percent of total elec tricity sales while the targets begin in 2017 in their approach. Commenters stated that EIA renewable generation data from 2013 and projected generation from wind and utility scale solar projects known to be under construction were used to estimate 2016 ba seline generation and that linear renewable energy growth is assumed beginning in 2017 through 2030 to achieve final renewable energy generation targets. Commenters also assumed that, in each year, states will achieve the greater of either the calculated renewable generation or the level needed to meet their mandatory RES target for that year as projected by LBNL, consistent with the EPA's "no backsliding" policy approach.

Commenters stated that their 'Market Potential Approach' results in a 2030 national renewable energy target of 912,660 GWh (excluding existing hydropower) or 21 percent of total U.S. electricity sales in 2030, which is a significant increas e over both EPA's proposed and Alternative RE A pproach. Commenters noted that their approach leads to higher renewable generation targets than the EPA Alternative RE Approach in the majority of states; however, by imposing the renewable generation cap of 40 percent of electricity sales, it also avoids placing an undue burden on states with high renewabl e potential and low electricity sales.105 3.6 INTERACTION OF B UILDING BLOCKS

This section addresses comments on the Interaction of Building Blocks. Responses to the comment topics of this section are discussed below along with summaries the specific public

c omments.
Commenters have raised a number of issues related to this section which are organized by topics (comments) below. Responses are provided for these topics

Comment 1: Multiple commenters stated generally that EPA should consider interactions
among the building blocks

. Response 1: EPA has considered the interaction of the building blocks, and disagrees with commenters who claim otherwise.
EPA has conducted analysis and adequately demonstrated the implications for the interactivity of the building b locks, and the relationship between them

. The substance of EPA’s analysis and rationale can be found in various sections of the final rule preamble and supporting documents (including sections V, sections VIII, the GHG Mitigation Measures TSD, and the fina l rule Regulatory Impact Analysis)

. An analysis of the combination of the BSER building blocks can be found in Section V.A.4.d

. Other analysis, which can be found in the GHG Mitigation Measures TSD and earlier parts of preamble section V, demonstrate that the stringency and timing of emission reductions achievable through use of each individual building block are feasible and achievable at reasonable cost, the stringency of the combination of building blocks is also reasonable, and the combination provides headroom and additional flexibility for states in setting standards of performance and for sources in complying with those standards to choose among multiple means of reducing emissions.
With regards to coal utilization and BB1, although under a BSER encom passing all three building blocks the volume of coal

- fired generation will decrease, that decrease is unlikely to be spread uniformly among all coal

- fired EGUs. It is more likely that some coal

- fired EGUs will decrease their generation slightly or not at a ll while others will decrease their generation by larger percentages or cease operations altogether. We would expect EGU owners to take these changes in EGU operating patterns into account when considering where to invest in heat rate improvements, with th e result that there will be a tendency for such investments to be concentrated in EGUs whose generation output is expected to decrease the least

. In addition, combining the building blocks at their full individual stringencies overstates the stringency of the BSER

. The combination is technically feasible and would be a “system of emission reduction” capable of achieving meaningful reductions in CO2 emissions from affected EGUs at a reasonable cost.
EPA has designed building blocks 2 and 3 so that their inte raction will be feasible

. Both building blocks are conservative, in the sense that they do not require either to be utilized to the maximum106 extent possible

. The RE goals for building block three are set based on a middle range of expected levels of develop ment, while the NGCC capacity factor goals are based on a capacity factor that is less than full load and i s set on an annual bases to leave room for the units to continue to fulfill multiple functions such as load following for short periods

. As described in Chapter 3 of the GHG Mitigation Measures TSD, NGCC units already run over large regions at the Building Block 3 capacity factors for extended periods

. Moreover, other units besides NGCC can provide similar ancillary service function

. As discussed in Pr eamble Section V.E and in Chapter 4 of the GHG Mitigation Measures TSD, multiple studies have demonstrated the potential for the levels of RE expected under this rule with minimal impact on system operations, and RE units can also be designed to provide an cillary services

. Another point is that the building blocks include several features that assure that affected EGUs may implement them. The building blocks may be implemented through a range of methods, including through the purchase of ERCs and emission trading. In addition, the building blocks incorporate “headroom.” Moreover, the source subcategory

- specific emission performance rates apply on an annual basis, so that short

- term issues need not jeopardize compliance. In addition, we quantify the emission performance rates based on the degree of emission limitation achievable by affected EGUs in the region where application of the combined building blocks results in the least stringent emission rate.
In section VIII.K., we discuss the processes for issuan ce and use of ERCs that can be included in the emission rate computations that affected EGUs perform to demonstrate compliance with an emission rate standard, which does not require implementation of the building blocks as specified as BSER. This ERC mecha nism, and other flexibilities afforded to states under state plan pathways, are analogous to the approach the EPA has used to reflect building blocks 2 and 3 in the emission rates representing the BSER, as discussed in section VI of the preamble. As discus sed in greater detail in section VIII.K., the existence of a clearly feasible path for usage of ERCs ensures that emission reductions achievable through implementation of the measures in building blocks 2 and 3 are available to assist all affected EGUs in achieving compliance with standards of performance b ased on the BSER.
To demonstrate potential compliance pathways states may choose, the EPA conducted detailed analysis of the power sector impacts which can be found in the Regulatory Impact Analysis, that includes the least

- cost implementation of the state goals and allows for the BSER measures as compliance (in addition to non

- BSER measures), to demonstrate the ability of the system and affected EGUs to comply with the requirements under the final CPP.

. The following are summaries of the specific public comments under this comment:

Commenters endorsed comments from EEI and generally stated that EPA evaluates each building block separately and that this simplified methodology ignores complex interactions

a mong building blocks in the integrated electricity system and results in technically flawed assumptions in setting state emission reduction goals

. Commenters emphasized that the EPA's building blocks are not achievable and fail to account for the interact ions between and among them.107 Commenters recommended that the building blocks be reworked so that the implementation of one will not directly negate the benefits of another. Commenters recommended that each Building Block be reviewed for actual effectivenes s when more realistic capabilities and technical feasibilities of those building blocks are determined.

Commenters stated that EPA's proposal is based upon a complex web of assumptions (many of them implausible) about future energy demand, dramatic shifts in generation sources, the addition of more intermittent sources for generation and reductions in energy use in 48 states. Commenters stated that each of these assumptions (what EPA ironically calls "building blocks") rests upon a weak foundation. Commente rs stated that as each "building block" crumbles, it places additional pressure on the remaining ones and takes EPA's plan from the implausible to the impossible. Commenters argued that as much as EPA touts the "flexibility" it is providing states, the pro posal places them into an energy straightjacket at the outset with each adjustment more painful economically and more risky for system reliability.

Comment 2: Commenters addressed the compl e mentary and cumulative benefits of the building blocks and the benefits of advanced technologies (e.g., wind generation)

. Response 2 : EPA agrees with the commenters that point out the current deployment of R E is already at high levels and st ate that there are synergies amo ng the building blocks that can increase thei r effectiveness

. EPA disagrees with commenters suggesting that the building blocks do not work effectively together

. See response at the beginning of the section for EPA’s response to these comments.

. The following are summaries of the specific public comments under this comment:

Commenters stated that EPA evaluated each BSER Building Block separately. Commenters stated that this approach fails to account for the additional emission reductions that result from the synergistic nature of advanced energy t echnologies, including but not limited to those technologies that comprise Building Blocks 2, 3, and 4. Commenters stated the Proposed Rule does not sufficiently account for the fact that the technologies covered by the four BSER Building Blocks are comple mentary and cumulative in nature, supporting feasible, cost

- effective statewide emissions targets. Commenters stated that the Proposed Rule underestimates the other benefits of advanced energy technologies, which, used together, create an electric power sy stem that is more efficient, reliable, resilient, and consumer

- focused.

Commenters disagreed that states cannot increase renewable energy deployment to the level expected by EPA because of technological limitations such as variability (which is purported to cause building block interaction issues). Commenters stated that many states are already successfully incorporating renewables. Commenters stated that the Electric Reliability Council of Texas (ERCOT), PJM Interconnection, and Midcontinent Independent S ystem Operator (MISO), are effectively managing ever higher levels of variable renewable generation. Commenters noted that Iowa and South Dakota generated 27 and 26 percent, respectively, of their total annual generation with wind power. Commenters contend ed that these states are not anomalies; seven other states supplied at least 12 percent of their total annual generation from108 wind in 2013. Commenters stated that the successful integration of wind energy in these states proves that it is possible to break down historical barriers to expanded renewable energy deployment. Commenters stated that integration has largely been accomplished using traditional solutions, such as creating larger balancing areas, ramp capability enhancement, better wind forecasting, and transmission expansion. Commenters stated that today, these traditional solutions are being coupled with advanced energy technologies, enabling even higher levels of
cost

- effective renewable energy.

Commenters stated that the technologies in the Build ing Blocks are synergistic in nature, providing cost effective emission reduction and electric system performance improvements that are beyond the simple summation of the potentials provided by each individual technology. Commenters stated the technologies of the Building Blocks also work collaboratively with the other advanced energy technologies allowed for compliance, meaning that states have a wide array of demonstrated, cost effective, and synergistic tools for emission reduction.

Comment 3: Numerous commenters indicated that there is a conflict with building block 2 (shifting generation to NGCC units) and building block 1 where coal

- fired EGUs would become load

- following which will undermine efforts to improve the heat rates.

Response 3: EP A disagrees with commenters suggesting that the building blocks 1 and 2 are in conflict

. See response at the beginning of the section for EPA’s response to these comments

The following are summaries of the specific public comments under this comment:

Comme nters explained that shifting use of coal units from base load in favor of natural gas units under building block 2 would negatively impact the heat rate improvements required under building block 1

.
Commenters stated that the increased utilization of exi sting NGCC units is intended to reduce the utilization and increase the cycling (turning on and off) of existing coal

- based units, which will undermine efforts to improve the heat rates of existing coal

- based units. Commenters stated that these units are m ost efficient when they run consistently at high capacity factors. Commenters stated that reduced load and operations of coal

- based units will erode any efficiency gains that might be made through heat rate improvements.

Commenters stated that Building Blo ck 1 requires heat rate improvements at coal

- fired units to reduce carbon dioxide emissions. Commenters stated that these efficiency improvements are offset by Building Block 2, which requires the coal

- fired units to operate at a reduced capacity so that t he natural gas dispatch to natural gas combined cycle (NGCC) can be increased from 51% to 70% in Georgia. Commenters stated that coal

- fired units are designed for base load power, and operate most efficiently at higher rates. Commenters stated that operati ng the coal

- fired units at reduced rates will prevent realization of any carbon dioxide reductions achieved by the heat rate improvement projects. Commenters recommended that EPA reassess the presumption that 6% HRI is achievable as an average of all coal

- fired units, and instead require states to include in their state plans a unit

- by

- unit assessment of what HRI is cost effective and achievable. Commenters stated that state goals would be adjusted accordingly.109 Commenters stated that coal based power produc tion is a key aspect of fleet diversity for Georgia utilities which helps mitigate potential fluctuations in fuel costs and provides reliable base

- load capacity. Commenters stated that the expected re

- dispatch toward natural gas for base

load power mandate d in the proposed rule will lower the capacity factor for the coal fleet. Commenters stated that a lower capacity factor will deteriorate the heat rate for coal units due to increased start up and ramp up losses, both on a per ton basis and as an average h eat rate. Commenters stated that coal units are most efficient when running at full capacity providing base

- load power on a consistent hour to hour and day to day basis. Commenters stated that an analysis of heat rate and capacity factor data for the large coal units, such as Plant Scherer, show an increase in heat rate as the capacity factor has decreased due to fuel switching to natural gas. Commenters stated that the failure to model the electricity system for Georgia dynamically invalidates the methodol ogy for goal setting in the proposed rule. Commenters stated that the final rule must be modified to reflect a realistic and feasible target for Georgia that is a compliance option and not a mandated level of heat rate improvement.

Commenters stated that t hey are greatly concerned that the state goals as proposed heavily rely on the re

- dispatching of base load units from coal

- fired EGUs to NG units. Commenters stated that this shift could in effect force coal

- fired EGUs to serve as "peaking units" and in ac tuality increase the net output rate of CO2 emissions due to the idling of coal

- fired EGUs.

Commenters stated that the requirement for coal EGUs to increase their efficiency through the Block 1 component conflicts with the requirement to then reduce the di spatch of coal EGUs in Block 2. Commenters stated that coal units, particularly in Texas, were designed to operate in a base load manner. Commenters stated that operation of these units at low capacity factors where the plants must start and stop more freq uently and/or ramp up and down will significantly degrade the very heat rate improvements that Block 1 seeks to require. Commenters stated that the 111(d) rule also fails to analyze the increased NOx and SO 2 emissions increases that will result from operat ing coal plants in this manner.

Commenters stated that the assumption that dispatch of NGCC plants will offset dispatch of coal

- fired EGUs does not account for the lower efficiency of coal

- fired EGUs when cycling

or operating at a lower capacity. Commente rs stated that base

- load plants operate most efficiently at their optimum capacity factor, as they do not have associated "fast ramp" capabilities like simple cycle combustion turbines. Commenters provided a figure to demonstrate claim.

Commenters stated t hat re

- dispatching coal generation to NGCC will negatively impact the heat rate of the remaining coal fleet. Commenters stated that coal units would have varying loads based on demand and that coal units do not operate efficiently under varying loads, so s wing loading would adversely affect the ability of the units to improve their heat rates.

Commenters stated that EPA does not appear to have considered that decreased utilization of existing coal units, a fundamental outcome of the shift in dispatch from c oal to NGCC applied in Building Block 2, has a detrimental effect on their heat rate, thus increasing emissions despite possible investments in efficiency improvements that would be required in the implementation of Building Block 1. Commenters stated that operation at partial load can increase net plant heat rate (and CO 2 emissions) by 4 to 8 percent, depending on boiler design and coal rank.110 Commenters stated that t he changes in coal

- fired EGU capacity factor required under Building Block 2 could very wel l eliminate any gains in efficiency achieved through Building Block 1.

Commenters stated that assumed heat rate improvements of Building Block 1 may not be realized as the lower coal plant capacity factors achieved by Building Block 2 would cause heat
rate s to increase and undermine the effectiveness of Building Block 1.

Commenters stated that Building Blocks 1 and 2 are incompatible and undermine the effectiveness of either building block. Commenters stated that these two Building Blocks cannot work in tan dem because they each depend on two very different scenarios as the most cost effective form of generating electricity. Commenters stated that Building block 2 undermines building block 1 and that coal units are a poor choice for intermittent operations fr om an energy efficiency and GHG emission perspective because they are harder to startup, shutdown, and operate under variable loads.

Commenters stated that significant increases in coal

- fired capacity factors are projected under all IPM scenarios examined. Commenters provided examples of substantial increases projected that are in direct conflict with historical data. Commenters stated that capacity factors at all coal

- fired units in the State of Ohio are projected by IPM to be between 80 to 85% by 2025. Co mmenters stated that this is in direct conflict with Building Block 2. Commenters stated that U.S. EPA's own model predicts internal conflicts with the proposed rule.

Commenters stated that BB1 and BB2 are contradictory in implementation. Commenters stated that if coal units are dispatched less they would have to cycle on and off more often, thereby increasing the heat rate.

Commenters stated that the increased usage of NGCC will cause more cycling of the coal

- fired units which in turn negatively imp acts their heat rate. Commenters stated that a shift to less

dispatchable, non

- emitting sources such as nuclear and renewable will also impact heat rate for the coal

- fired units. Commenters stated that this adjustment would create more cycling and more thr ottling of coal plants thereby creating a decrease in heat rate efficiency of approximately 1%.

Commenters stated that the re

- dispatch of natural gas plants ahead of coal plants under BB2 will negatively impact coal plant efficiency by requiring them to r un at less than optimal capacity. Commenters stated that c oal

- fired power plants heat

- rate efficiency would be undermined by intermittently running at lower capacity factors and/or shutting down to comply with the proposed rule. Commenters cited data that indicates that reducing the output of the unit by 20 percent will increase the heat rate by almost 2 percent. Commenters stated that EPA should adjust the BB1 target accordingly.

Commenters stated that the EPA's proposed Heat Rate Improvement (HRI) of 6% i s based on assumptions that "best practices" combined with equipment upgrades will achieve the desired results. Commenters stated that the EPA assumes, but does not analyze, whether these "improvements" will work in concert with the other building blocks. For instance, c ommenters stated that the building block to shift coal generation to natural gas by increasing combined cycle natural gas capacity factors will result in lowering coal generation capacity factors. Commenters stated that lower capacity factor s in coal plants can increase heat rate. Commenters stated that if111 coal plant capacity factors are decreasing, and thus efficiency is degraded, then increasing efficiency in other ways may only offset efficiency losses caused by lower capacity factors.

Com menters stated that the proposal would effectively decrease unit efficiencies for many of today's workhorse units by relegating them to a secondary "swing load" position in the dispatch order. Commenters stated that steam units operate most efficiently at or near their highest level of output and suffer dramatic fuel cost penalties when operated at less than maximal conditions. Commenters stated that under the proposed rule, many of the fossil units that currently serve the market in a base

- load capacity wi ll, through Block 2 re

- dispatching, see a reduction in duty cycle, effectively decreasing efficiency and increasing their emissions per net megawatt

- hour.

Commenters stated Block 1 heat rate improvements interact with Block 2 re

- dispatch to natural
gas an d Block 3 increased deployment of renewable energy. Commenters noted that if there is an increase in NGCC generation and coal units are utilized less, then coal units will be operating at lower, less efficient load points than designed. Commenters noted fo r example, when their very efficient units operate at minimum rather than maximum load, the decrease in efficiency is 30%. Commenters explained that coal units are designed to operate most efficiently at higher loads. Commenters stated that the need to run these coal units at lower capacity factors will necessarily decrease the efficiency of these same units for which the EPA is assuming a 6% efficiency improvement under Building Block 1. Commenters stated that the EPA's envisioned improvement in efficiency for coal

- fired units cannot be realized with the substantially reduced capacity factors envisioned by the proposed rule.

Commenters stated that Building Block 2 assumes the ability to shift generation from coal

- fired plants to NGCC plants, thereby raising the average NGCC plant capacity factor to 70%. Commenters stated that this shifting of generation will reduce the average efficiency of the coal

fired units. Commenters noted that the EPA has shown a strong relationship between lower capacity factors and lower coal plant efficiency. Therefore, commenters stated that one of the impacts of Building Block 2 will be to offset some of the efficiency improvement efforts taken by coal

- fired plants to meet Building Block 1, thereby making Building Block 1 even har der to achieve. Commenters stated that this reinforces the necessity to analyze BSER Building Blocks in an integrated manner rather than individually.

Commenters stated that the achievability of each building block, as prescribed by EPA, is questionable du e to overly aggressive assumptions and the real world consequences of collectively and simultaneously implementing the building blocks. Commenters noted for example, EPA assumes that existing coal fuel

- fired electric generating units can improve efficiency by 6%. Commenters stated that efficiency improvements are best realized when a unit is operating at full load; yet, Building Block 2 (the re

- dispatch of natural gas combined cycles) would lower the utilization of coal fuel

- fired units away from their most

- efficient operational point.

Commenters stated that the EPA did not evaluate the feasibility of achieving the heat rate improvements called for under Building Block 1 in conjunction with the changes to natural gas dispatch at the expense of coal

- fired ge neration as called for under Building Block 2. Commenters stated that increasing the dispatch of natural gas combined cycle plants to 70 percent of capacity will make existing coal

- fired units operate in a significantly less efficient112 manner. Commenters no ted that coal

- fired plants are at their most efficient when they are running at or near 100 percent capacity. Commenters stated that if transmission operators reprioritize the dispatch of natural gas based on the proposed CPP, it will force coal

- fired plan ts to operate at a lower utilization rates. Commenters stated that running plants at a lower utilization rate will result in a lower overall efficiency for coal

- fired plants, which causes a de facto net heat loss.

Commenters stated that when coal

- fired pla nts assume a reduced operating profile as may be possible if other generation is being dispatched in lieu of coal

- fired generation, regardless of the cost of that alternative generation, a number of problems arise that make EPA's targets for Building Block 1 even harder to achieve. First, commenters stated that running coal

- fired plants at a lower capacity factor may increase the need for more unit start

- ups and shutdowns. Commenters stated that the end result is additional heat loss, because coal

- fired pla nts operate less efficiently during frequent startups as well as under load following dispatching. Second, commenters stated that start

- up and shutdown procedures consume auxiliary power, which results in additional reported emissions and heat loss. During this period, commenters noted that the plant may in fact produce no net generation. Commenters stated that the EPA's calculations do not assume auxiliary power loss or the possibility of a lower output factor as a result of the proposed rule. Commenters s tated that, as a result, plant operators are being asked to make up for several percentage points of lost efficiency before they can start counting improvements towards the net gain of 6 percent. Commenters stated that Building Block 1 improvement targets are unrealistic combined with the additional losses associated with parasitic load identified above. Commenters argued that the goals of Building Block 1 appear to be mutually exclusive to the goals of the other three building blocks. Commenters stated tha t the underlying basis for EPA's heat rate improvement claims, a Sargent and Lundy study on heat rate improvements, does not take into account whether potential improvements have already been made.

In lieu of the unrealistic heat rate reductions EPA target s in its proposed CPP, commenters recommended that the EPA develop a work practice standard for heat rate improvements at designated facilities instead. Commenters referred to the comments filed by AEP for an excellent example of the rationale and logic of how this viable alternative could be implemented under Section 111(h)(1) of the CAA. Commenters requested that the Administrator consider the benefits of such an approach in finalizing the proposed CPP.

Commenters stated that the reductions observed in th e Sargent & Lundy case study were done on a facility operating at full capacity, thus giving maximum opportunity for any upgrades in equipment to be observed. Commenters stated that it is very important to note that the heat rate improvements for the facil ity even with replacing outdated equipment at full capacity were only 4%, which is substantially lower than the 6% established by U.S. EPA. Commenters stated that when facilities operate at less than maximum capacity, the heat rate improvements will not be as pronounced as they were observed in the Sargent & Lundy case studies. Commenters stated that it is also important for U.S. EPA to factor in that Building Block 2 of the proposed rule would cause coal units to operate at less than the designed capacity and, thus have higher heat rates than they would at normal operating conditions.

Commenters stated that the EPA's BSER determination fails to consider the interrelationship of the four building blocks, and thereby disregards the impacts of the building bl ocks on each other.113 For example, the commenters noted that redispatching steam generation to NGCC units (Building Block 2) could limit the availability of heat rate improvements at coal

- fired EGUs (required by Building Block 1).

Commenters stated that Building Blocks 1 and 2 compete on multiple fronts; including plant efficiency reductions at lower loads and the reality that implementation of Building Block 2 negates the opportunity for New Hampshire to make heat rate improvements under Building Block 1 . Commenters stated that the combination of Building Blocks 1 and 2 in their current form cannot realistically be presented as viable tools to achieve compliance in New Hampshire. Commenters stated that it is a widely understood concept that coal

- fired ste am EGU's are designed to attain peak efficiency when operating at or near the rated maximum unit load. Commenters stated that operation at loads less than the rated maximum unit loads negatively impact the EGU's net heat rate. Commenters provided a chart ( Figure 5 ) with quantitative results to illustrate that for coal

- fired EGU's of various capacities, heat rates improve significantly with increasing capacity factor until they eventually stabilize at capacities greater than 70 percent.

Commenters stated th at redispatching to NGCC to 70% capacity factor could result in some coal EGUs being operated at lower loads and this would have a negative effect and increase CO2 rate for coal units because heat rate would increase.

Comment 4: Commenters stated that the re is a financial inconsistency between building blocks 1 and 2, which affects the ability and incentive to finance heat rate improvements to coal

- fired units.

Response 4: EPA disagrees with commenters claiming building blocks 1 and 2 are inconsistent

. See response at the beginning of the section for EPA’s response to these comments

The following are summaries of the specific public comments under this comment:

Multiple commenters indicated that there is a financial inconsistency between building block 2 (re

- dispatch to NGCC) and building block 1 (as re

- dispatch to NGCC occurs, coal fired EGUs would be used less, which affects the ability and incentive to finance heat rate improvements). The commenters argued that investments in heat rate improvements to coal

- fired units under building block 1 would be lost as coal

- fired generation is replaced with gas

- fired generation under building block 2.

Commenters stated that building block 1 seems fundamentally at odds with building block 2. Commenters questioned t he incentive for utilities to make heat rate improvements (building block 1) at a coal

- fired power plant (at a cost of hundreds of thousands or millions of dollars) only to not be able to run that unit as often, if at all, because of compliance with block 2 (where natural gas units would be dispatched first). Commenters asked EPA how it thinks a utility would finance such a project (heat rate improvements) if its creditors can have no assurance that the plant would be operated sufficiently (due to building block 2) to pay back the debt service? Commenters stated that EPA must address these issues and amend building block 1 to enable realistic heat rate improvements at power plants.114 Commenters questioned the reasonableness of investing in heat rate improvemen ts only to then retire the plants based on the re

- dispatch assumptions in Building Block 2 and the 2020 interim performance requirements. Commenters stated that EPA fails to adequately address the inconsistency of using heat rate improvements in coal

- fired units to calculate Building Block 1 savings, only to then substantially negate those savings by re

- dispatching from those improved coal

- fired units to natural gas

- fired units for the savings presented in Building Block 2.

Commenters stated that investing millions of dollars in technology to improve heat rates at coal units that are expected to have declining use would be a wasteful allocation of scarce funds.

Commenters stated that increasing the capacity factor of NGCC sources to 70% (Building Block 2) r epresents the most costly option among the four building blocks. Commenters stated that Building Block 2 is a disincentive for coal

- fired sources to invest in building block 1 (the lowest cost building block) because coal

- fired plants (high in the dispatch order with low generation costs) would incur stranded costs for heat rate improvements when they are no longer required to operate at base

- load.

Commenters stated that the owner of a coal

- fired EGU would be hesitant to invest in heat rate improvements if the unit would be dispatched less.

Commenters stated that at lower capacity factors (caused by BB2), the coal plants have less opportunity to earn back the money invested in heat rate improvements and environmental upgrades.

Commenters stated that they a re concerned that much of the unit heat rate benefit from Block 1 projects will be unrealized because the affected coal units are then required to operate at reduced loads to meet Block 2 re

- dispatch targets. Commenters stated that the assumed Block 1 heat rate improvements are overly optimistic and need to be adjusted along with the interim and final targets. Commenters provided specific data ( Rawhide Unit 101) to show that heat rate increase 3.4% between operating at full load and 70% load. Commenters sta ted t he proposed CPP cost analysis should recognize that any assumed economic benefit from BB1 efficiency projects will be compromised by BB2.

Commenters noted that B lock 1 involves reducing the carbon intensity of generation at individual affected EGUs t hrough heat rate improvements, but under Block 2 where the coal plants will be operating at low capacity factors, the heat rate improvements are less than what can be expected at full load. Commenters stated that the capital invested to improve heat rate w ill be difficult to recover at the lower operating rates.

Commenters stated that increasing the capacity factor of the NGCC fleet to 70% in the Electric Reliability Council of Texas (ERCOT) region under Block 2 reduces the capacity factor of the existing E RCOT coal

- fired fleet and consequently precludes the implementation of the efficiency improvements under Block 1. Commenters stated that for a majority of the coal units in the ERCOT region, efficiency improvements will not be economically feasible when co upled with the re

- dispatch of NGCC in Building Block 2, because the high costs of improvements would likely not be recouped due to reduced operating hours and lower capacity factors on coal units, even if significant coal retirements are assumed.115 Commente rs stated that b uilding block 2 calls for a re dispatching EGUs from coal to gas with a 70 percent capacity factor for existing natural gas combined units. Commenters stated that one would expect coal plants to run more often with the large investments nee ded to improve heat rates under building block 1, but the CPP would force dispatch on an environmental basis and not necessarily the lowest cost economic basis.

Comment 5: Comments indicating there is a conflict between the four building blocks and reanalysis should be conducted.

Response 5 EPA disagrees with commenters that assert the building blocks do not work together, or asserting that EPA has not adequately evaluated their interaction

. EPA’s analysis is adequate and a reanalysis is not needed

. See response at the beginning of the section for EPA’s response to these comments

. The following are summaries of the specific public comments under this comment:

Numerous comme nters indicated that there is a conflict with building block 2 (re

- dispatch to NGCC), building block 3 (RE), building block 4 (EE) and building block 1 (coal fired EGUs would become load

- following which will undermine efforts to improve the heat rates). Th e commenters stated that all analyses related to the building blocks should be re

- evaluated with consideration that the building blocks are not complimentary.

Commenters stated that under building block 2, EPA is requiring re

- dispatch from coal

- fired EGUs to NGCC. Commenters stated that this results in more coal

- fired EGUs being dispatched as load

- following rather than providing base load at high capacity factors. Commenters stated that EGUs have higher heat rates when operating as load

- following units and during periods of startup and shutdown. Commenters stated that EPA should adjust its assumptions and allow states to modify their goals to account for reduced heat rate that occurs due to load following, variable renewable energy resources. Commenters app eared to be highlighting the issue of reduced heat rates for coal EGUs as a result of decreased utilization under building block 2, while simultaneously requiring heat rate improvements under building block 1. Commenters stated that if heat rate improvemen ts were made, decreased plant utilization (lower load operation and increased cycling) would degrade the plant's heat rate, partially or fully offsetting the effect of the heat rate improvement projects. Commenters stated that EPA must address these issues and amend building block 1 to enable realistic heat rate improvements at power plants.

Commenters stated that certain target levels of intermittent renewable energy sources captured in Block 3 will negatively impact heat rate improvement expectation captu red in Block 1. Commenters stated that this is the case since coal units would be expected to operate with more swing to follow a more erratic load profile created by intermittent renewable energy sources. Commenters stated that re

- dispatch to NGCCs in Blo ck 2 will also affect the heat rate improvements in Block 1. Commenters stated that EPA has not considered how the four building blocks affect each other in praxis but have only considered them individually on an isolated theoretical basis. Commenters stat ed that coal units would be forced to adjust output to follow load changes, reducing their efficiency.116 Commenters stated that favoring the dispatch of natural gas combined cycle units over coal, and greater penetration of intermittent renewable generation on the grid, BOTH proposed by EPA in 111(d) as a means of reducing CO2 emissions, could effectively negate any measurable and sustainable improvement in heat rate across the coal

- fueled generating fleet. Commenters stated that the Initial NERC Report expla ins that Building Block 2 will cause coal units to cycle more often, resulting in lower capacity factors and higher heat rates; the heat rate improvements assumed by Building Block 1 are unlikely to be achievable. Commenters cited specific data to support this argument.

Commenters stated that the effect of the EPA's other blocks compete with improving onsite efficiency at existing coal

- fired EGUs, most notably the re

- dispatching under Block 2. Commenters stated that EPA's assumed 6% heat rate improvement fo r coal

- fired EGUs does not take into consideration that EPA's other three proposed building blocks actually create an unintended effect of increasing the average heat rate of EGUs and making existing coal

- fired EGUs less efficient. Commenters stated that t he other three blocks are intended to decrease the utilization or capacity factor of existing coal

- fired EGUs; however, efficiency decreases as the capacity factor decreases. Commenters stated that the result of the EPA not taking into consideration both t he future penalty of additional environmental controls and capacity factor decreases caused by the rule will make the 6% heat rate improvement an unachievable standard of performance.

Commenters stated operating a unit at reduced capacity will increase its heat rate and it could negate any gains that may have been made under building block 1. Commenters stated that Building Blocks 2

- 4 will force the coal

- fired fleet to assume a greater load

- following role in electric generation. Commenters provided data a nd multiple figures to illustrate the impact of unit capacity and load on heat rate

. Commenters stated that they believe there is room for improving a plant's heat rate. Commenters stated that Building Blocks 2

- 4 will most likely result in an overall red uction in the utilization of the coal fired units. Commenters stated that reducing the average operating load of the plant will result in a degradation of the heat rate and loss of some of the efficiency gains made as a result of EPA's proposed coal fired heat rate building block.

Commenters stated that Building Blocks 2 and 3 will shift coal fired units from base

- loaded operation to low load or cycling load and will increase those units heat rates, negating much, if not all, of the potential benefits achie ved with heat rate improvement methods at full load.

Commenters provided detail (in table format) on how low load and/or cycling profiles (cause by building blocks 2

- 4) affects heat rate improvement (HRI) strategies for coal fired units. Commenters discussed the effect of low load and cycling on the following 17 HRI strategy areas: coal transport/conveying/grinding, boiler operation/overhaul with new heat transfer surface, neural network (NN) control system, intelligent soot blower (ISB) system, air heater leakage mitigation, air heater acid dew point reduction, turbine overhaul and upgrade, feed water heater, condenser, boiler feed pump, forced draft (FD) and induced draft (ID) fan improvement, variable

- frequency drive (VFD), flue gas desulfurization (FGD) system, particulate system, selective catalytic reduction (SCR) system, boiler water treatment, cooling tower.117 Commenters stated that the annual capacity factor may be lower in the future if Building Blocks 2 and 3 are implemented. Commenters performed detailed analysis of six plants (with a total of nine units in the electric cooperative fleet) to understand how varying dispatch loads affect the heat rate of units within the fleet. Commenters provided significant data in tables and figures. Pl ants analyzed by the commenters are Hoosier Energy (Merom Units 1 & 2), San Miguel Electric Cooperative (San Miguel), Sunflower Electric Power Corporation (Holcomb Unit 1), Big Rivers Electric Corporation (Robert E. Green Units 1 & 2), Arizona Electric Pow er Co

- Op (Apache Unit 3), Southern Mississippi Electric Power Association (Morrow Units 1 & 2). Commenters provided data which shows that efficiency steadily decreases as the load decreases.

Commenters argued that all four building blocks overestimate what is technically feasible, and/or entail costs significantly higher than those projected by EPA. Commenters stated that the 6% goal for heat rate reduction is too high. Commenters stated that building blocks 2

- 4 will make existing coal fired plants less e fficient due to low load and reduced capacity, making efficiency goals in building block 1 unachievable. Commenters stated that it cannot possibly meet its target without pursuing Blocks 1, 2, 3, and 4, and cannot meet Block 1 if it succeeds with the other three Blocks

Commenters stated that EPA's Building Block 1 assumption of a 6% heat rate improvement across the existing coal generation fleet, to be achieved through 4% improvement via best practices in operations and 2% via capital investments in upgrade s, is unrealistic and widely considered to be unachievable. Commenters stated that building block 1 is unachievable due to building blocks 2

- 4.

Commenters stated that EPA has failed to address the interaction of Building Block 1 with Building Blocks 2 a nd 3. Commenters stated that Building Blocks 2, 3, would decrease the average capacity factor of coal

- fired steam EGUs by forcing them to run at lower levels and that Building Block 4 will result in coal

- fired generation cycling up and down in order to bal ance intermittent loads. Commenters stated that running coal EGUs at lower capacity factors with increased cycling will greatly decrease the efficiency of these units.

Commenters stated that the purpose of Building Blocks 2, 3 and 4 is to reduce load on co al units which will make them operating at lower load as intermediate rather than base

- load units. Commenters stated that this will increase their heat rates and CO2 emissions.

Commenters stated that the implementation of Blocks 2, 3, and 4 would decrease the average capacity factor of coal

- fired steam EGUs, forcing them to run at lower levels. Commenters stated that the increased use of renewable energy will clearly result in the coal

- fired generation cycling loads up and down in order to balance intermitt ent loads from new wind and solar generation. Commenters recommended that EPA factor in the offsetting impacts of these conditions on the heat rates of existing coal

- fired units in setting the efficiency improvements under Building Block 1.

Commenters stat ed that some coal units may cycle more often as result of increased NGCC and renewables, which may reduce the benefits of the assumed heat rate improvements. Commenters urged EPA to evaluate the impact of increased operation of NGCC units and increased dep loyment of renewables on the efficiency of the existing fleet.118 Commenters stated that EPA recognizes that units operating at lower than optimum capacity factors will have sub

- optimal heat rates. Commenters cited various references and data to support this claim. Commenters stated that lower

- capacity factors (particularly due to the cycling) will cause an increase in heat rates. Commenters stated that building blocks 3 and 4 will also necessarily displace coal generation, further reducing coal unit capacity factors and increasing their heat rates. Commenters stated that EPA completely failed to take these issues into account in its building block 1 calculations.

Commenters stated that the Proposed Rule will likely lead to increased coal

- fired unit cycling and low

- load operation, which has the practical effect of increasing CO2 emission rates. Commenters stated that the increases in coal

- fired unit heat rates due to increased cycling and low

- load operation could effectively eliminate all CO2 emissions benefits resulting from Building Block 1. Commenters stated that that EPA did not properly account for the degradation of coal

- fired unit heat rates and additional maintenance needs resulting from increased unit cycling and low

- load operation and that EPA inappropr iately established BSER.

Commenters stated that EPA must make substantial changes to the way it calculates the emission reductions of BB1. Commenters stated that EPA's block one proposal for coal

- fired steam EGUs fails to take into account the impact of co mplying with the MATS Rule and other pollution control regulations, as well as the likely impacts on EGU heat rates of implementing the other BSER building blocks.

Commenters stated that a constraint on heat rate improvement is the reduction in capacity fa ctor of coal plants, as a result of Building Blocks 2, 3 and 4. Commenters stated that t he heat rate becomes more unfavorable as the unit operates at lower loads. Commenters cited data that supported claim.

Commenters stated that EPA overlooked the negati ve impact that operating at partial load may have on a unit's heat rate. Commenters cited references to support this claim. Commenters stated that EPA does not account for this factor at all in developing its proposed emission guidelines, instead assuming that a unit's heat rate is independent from its utilization. Commenters stated that this omission is egregious, given that the remaining portions (BB 2, 3, and 4) of EPA's proposed BSER are premised on reducing the capacity factor of existing EGUs well below their historical levels.

Commenters stated that increasing in

- state gas generat ion to comply with BB2 drives coal

- fired resources to become load

- following (and dispatched at lower loads), thereby reducing the efficiency of the coal fleet and making it impossible to meet BB1's heat rate improvement target. Commenters stated that EPA c laims to have demonstrated that the emission reductions achieved by each building block are independently attainable, and therefore can simply be added together to determine an overall goal. Commenters stated that under the CAA, it is EPA's burden when det ermining BSER to show that the building blocks, applied simultaneously and in concert, are "achievable" and have been "adequately demonstrated" for each state. Commenters stated that EPA has failed to make this demonstration. Commenters stated that prior t o finalizing the rule, EPA must present analysis or modeling that shows the reductions that can actually be achieved when implementing all four building blocks simultaneously for each state, as well as nationally.119 Commenters stated that the re

- dispatch of NGCC units described in BB2 and the increase in the use of renewable energy described in BB3 will likely increase the cycling of coal units, thus pushing coal units to operate more often at less efficient points on their load curves, increasing their aver age heat rates. Commenters stated that EPA should consider the impacts of the operating assumptions prescribed by Building Blocks 2 and 3 on coal unit operating heat rate improvements and use its corrected analysis to review the appropriate heat rate impro vement assumption in Building Block 1.

Commenters stated that the BSER methodology does not consider the interaction between building blocks. Commenters stated that the application of building block 2 and building block 3 will result in the complete displa cement or reduced use of certain coal resources. Commenters stated that s uch reduction or displacement changes the economics and feasibility of investing in heat rate improvement projects. Commenters stated that the application of building blocks 2 and 3 r educes the viability of heat rate improvement projects and therefore makes EPA's assumption regarding a six percent heat rate improvement less achievable.

Commenters stated that the building blocks presented by the CPP have been separated and calculated i ndependently but in reality are dependent. Commenters stated, for example, building block 2 requiring additional NGCC generation will require additional cycling of other fossil generation, increasing its heat rate and reducing plant efficiency. Likewise, T he commenters noted that the low carbon generation required in building block 3 and energy efficiency in block 4 will require additional cycling and increase plant heat rates and decrease efficiency. Commenters stated that the low carbon generation require d in block 3 will increase the distance electricity must be transported and transferred from system to system which will reduce the efficiency of the electricity system which the CPP states it wants to improve. Commenters stated that the rule also places c onstraints of states emission rates to use the lowest emitting units regardless of location. Commenters stated that the building blocks create complexities and inefficiencies to the generating and transmission system that were not taken into consideration by the CPP when developing state rates. Commenters requested that the CPP take the interdependencies of each building block and the inefficiencies created by implementing each block independently into consideration when finalizing state emission rates.

Com menters stated that the EPA's push for more renewable energy does not take into account how increased renewable energy will impact existing generation resources in the states. Commenters stated that increased renewables will lead to increased cycling of fo ssil resources (particularly NGCC, but possibly also coal) and will decrease efficiency of those resources due to the intermittency of most renewable generation resources.

Commenters argued that the EPA ignored the impact of the building blocks on each oth er, and that each building block will impact the others when implemented simultaneously

. For example, commenters stated that increased generation from variable renewable resources, like wind energy, will likely require utilities to operate some natural gas combined cycle units at lower capacity so that the remaining capacity can be ramped up quickly to support any sudden reductions in wind generation. However, the commenters noted that operating at lower loads to preserve back

- up capacity in support of vari able renewable generation may interfere with a state's ability to achieve EPA's assumed 70

- percent utilization rate for existing NGCC units. Commenters stated that another example of a potential conflict would be the lower loads,120 increased cycling, and inc reased startups and shutdowns of coal

- fired units needed to allow higher utilization of existing NGCC units to meet building block 2, all of which will reduce the efficiency of coal

- fired units, increase CO2 emission rates, and interfere with efforts to ac hieve building block 1. Commenters stated that the EPA's failure to consider the trade

- offs that its building blocks will require, by analyzing each one individually without accounting for the constraints presented by the others, causes the EPA to overesti mate the reductions achievable and results in unreasonably stringent emissions goals.

Commenters stated that addition of large amounts of variable wind and solar resources under Building Block 3 likely will require increased use of natural gas

- based units to provide back

- up and ramping. Commenters stated that units cannot run continuously at high utilization rates and also simultaneously be available to support renewable generation, which requires frequent increases and decreases in generation in response t o variable renewable output. Commenters explained that Building Block 2 calls for a re

- dispatch from coal to gas, which would require utilities to run gas plants more. Commenters stated that this ignores interactions between and among the Building Blocks, especially with additional large amounts of variable solar resources. Commenters noted that renewable resources require a certain amount of capacity that can provide back

- up and ramping (i.e., new NGCC and gas turbines). Commenters stated that if these uni ts are required to be run at high utilization rates because coal or less efficient units have been backed down or retired early then they will not be available for back

- up and ramping.

Commenters stated that the EPA did not evaluate the feasibility of achi eving the heat rate improvements under Building Block 1 in conjunction with the changes to dispatch called for under Building Block 2. Commenters stated that increasing the dispatch of natural gas combined cycle plants to 70 percent of capacity will change the way that existing coal

- fired units are dispatched such that the overall performance would be significantly less efficient. Commenters stated that coal

- fired plants are at their most efficient when they are running at or near 100 percent capacity. Comm enters stated that if transmission operators re

- prioritize the dispatch of natural gas, this would likely force coal

- fired plants to operate at a lower output factor assuming that the assumptions from Building Blocks 3 and 4 are realized as EPA has envisio ned. Commenters stated that running plants at a lower output factor will result in a lower overall capacity factor for coal

- fired plants, which causes a de facto net heat loss.

Commenters stated that when coal

- fired plants assume a reduced operating profil e, a number of problems arise that make EPA's targets for Building Block 1 even harder to achieve. First, commenters stated that running coal

- fired plants at a lower capacity factor increases the need for
more start

- up and shut

- down operations. Commenters stated that the end result is additional heat loss, because coal

- fired plants operate inefficiently during these processes. Second, commenters stated that start

- up and shut

- down procedures consume auxiliary power, which results in additional reported emiss ions and heat loss. Commenters noted that during this period, the plant may in fact produce no net generation. Commenters stated that the EPA's calculations do not assume auxiliary power loss or the possibility of a lower output factor as a result of the p roposed rule. As a result, commenters stated that plant operators are being asked to make up for several percentage points of lost efficiency before they can start counting improvements towards the net gain of 6 percent.121 Commenters suggested that the EPA s hould adjust the average expected heat rate improvement based on the interplay of all of the Building Block assumptions. Commenters expressed concern that each utility will have to evaluate whether it is prudent to invest monies to improve heat rate knowin g that dispatch will be curtailed. Commenters stated that the end result could be the premature shutdown of coal

- fired plants in Indiana in excess of EPA's estimates, given that the agency did not take some of the aforementioned problems into consideration in its modeling efforts.

Commenters stated that o verall, the EPA should consider the interdependency impacts of the building blocks. Commenters stated for example, NGCC units are currently used to balance variation in renewable generation. Commenters note d that building block 2 assumes a 70% capacity factor for NGCC units. Commenters stated that adding new renewables under building block 3 would require the addition of even more new fast

- ramp resources such as NGCC to balance the additional renewables. The refore, commenters stated that the issues presented by EPA's overly optimistic assumptions in building blocks 1, 2 and 4 are compounded by these interdependency impacts.

Commenters stated that Block 1 is significantly undermined on a technical and economic basis by the other "building blocks." Commenters stated that the single best way to improve coal

- fired unit efficiencies is to turn them on and let them run. Yet, commenters noted that Building Blocks 2, 3, and 4 are intended to cause a decrease in capaci ty factors for coal

- fired EGUs. Essentially, commenters stated that Blocks 2, 3, and 4 directly conflict with Block 1. Commenters asserted that the EPA's BSER is internally inconsistent and must be reconsidered.

Commenters stated that the building blocks a re clearly interrelated. Commenters noted for example, it would be nonsensical to undertake uneconomic capital projects to improve heat rate efficiency at a coal

- fired plant under Building Block 1 (assuming arguendo any exist), only to have the capacity fa ctor of the coal

- fired plant severely curtailed by Building Block 2. In addition, commenters stated that because Building Blocks 3 and 4 are unattainable for Alabama, changes to State emission rates would have to be made up for under Building Block 2, effe ctively changing the stringency of Building Block 2 in Alabama. Commenters stated that it is unrealistic for EPA to assume that a company would simply be able to increase reductions from one building block to offset any impossibilities presented by another . Commenters stated that the building blocks simply cannot be reconciled and, accordingly, are arbitrary and capricious.

Commenters stated that the EPA has failed to account for the impacts the building blocks have on each other. For example, commenters st ated that the heat rate improvements in Building Block 1 are undermined by the change in dispatch required in Building Block 2. Commenters stated that increased dispatch of natural gas combined cycle units will likely result in a responding change in load for coal

- fired units and cause base

- load units to "cycle" more often. Commenters stated that a change in dispatch to follow load, instead of base

- load operation, can dramatically reduce a unit's operating efficiency and raise the heat rates and CO2 output. Commenters noted that an example of how this change in dispatch may affect plant operations can be seen in the cycling of a unit. Commenters stated when the unit goes through the startup process, natural gas and coal are burned to bring the boiler and ass ociated equipment back to operating temperature. Commenters noted that this process consumes heat input and auxiliary load but does not immediately serve electric load on the grid. Additionally, commenters noted122 that depending on the layout of the facility , a load drop in the evening may necessitate the use of duct burners to maintain the flue gas temperature as it enters pollution control equipment such as an SCR. Commenters stated that this increases the energy usage with no direct addition to electric ge neration that reaches the grid. Commenters noted that the EPA has acknowledged in multiple technical support documents, including the GHG Abatement Measures document that operating a coal

- fired electric generating unit as a base

- load unit is more efficient than operating that same unit as a load following unit to respond to fluctuations in customer electricity demand. Yet, commenters stated that when setting CO2 targets that include increased use of renewables (Block 3) and combined cycle natural gas units (Block 2), the negative impact on heat rate at existing coal units is not addressed. Commenters noted that it is assumed all units can reach a 6 percent heat rate improvement goal, irrespective of a change in dispatch.

Commenters stated that while EPA has erroneously concluded that states can meet each building block separately, it has also erroneously concluded that states can meet each building block simultaneously. In the case of re

- dispatch, commenters stated that the EPA has failed to consider the dir ect relationship between renewable generation and the dispatch of natural gas units. Commenters stated that renewable generation is intermittent and highly variable and requires balancing and backup services from the electric grid. Commenters noted that th ose backup services are predominantly provided by natural gas units that typically operate at lower capacity factors in order to be able to respond to swings in renewable load. Commenters stated that setting arbitrary dispatch levels under Building Block 2 will undermine the ability of natural gas units to provide the backup and balancing functions necessary to meet the increased renewable requirements of Building Block 3. Commenters stated just like the dispatch requirements of Building Block 2 undermine t he heat rate improvements of Building Block 1, the dispatch requirements of Building Block 2 do not support the increased renewable requirements of Building Block 3. Commenters stated that while each building block may look promising on paper, they simply do not achieve the targeted emission reduction outcomes when the blocks are imposed simultaneously because the blocks will work against each other.

Commenters stated that t he re

- dispatch of NGCC units (Block 2) and the increase in use of renewable energy ( Block 3) will likely increase the cycling of coal units and push coal units to operate at less efficient points on their load curves. Commenters stated that the efficiency difference between low load and optimum efficiency (typically near full load) can be significant, and that these factors were not considered by the EPA when determining the level of heat rate improvement achievable under Building Block 1. Commenters recommended that the effects of each of the building blocks need to be evaluated in an int egrated manner. Commenters stated that the EPA needs to consider the impact of Block 2 and Block 3 operating assumptions on coal unit operating heat rates when determining the appropriate Block 1 heat rate improvement value. Commenters stated that this can be accomplished by consulting with the states or, at the states direction, the states' ISOs, who have the modeling capability to identify the interaction between the building blocks.

Commenters stated that EPA takes an approach that demonstrates each of the blocks of measures it identifies to achieve the reduction (Block 1: heat rate improvement at existing coal plants, Block 2: switching from coal to gas, Block 3: relying on low carbon, non

- fossil fuels, and Block 4: increasing the role of energy efficie ncy) is technically feasible, economically practicable and consistent with the APA standards, and the assumptions for each separate analysis are not123 reconciled. Commenters explained that while this may make sense from the point of view of passing legal mus ter to outline worst case scenarios, the use of different and contradictory assumptions is troubling.

Comment 6: Commenters addressed the interaction of building blocks 1, 2, and 3 and encouraged consideration of the remaining book life of coal

- fired units and pollution control equipment

. Response 6: EPA disagrees

. Book life and BSER are discussed in Preamble Section V.A

. See response at the beginning of the section for EPA’s response to comments about interaction among the building blocks

.
The follo wing are summaries of the specific public comments under this comment:

Commenters noted that the EPA's NODA requests comment on whether consistent with the BSER, the overall framework proposed includes sufficient flexibility with respect to adequate time f or the implementation of emissions reduction strategies and the consideration of cost. Commenters stated that a relevant concern with EPA's BSER approach is the interaction of Block 1 with Blocks 2 and 3. Commenters stated that shifting generation from exi sting coal

- fired generation assets and requiring these units to operate at lower capacities or as load

- following units is counter

- intuitive to achieving and sustaining heat rate improvements. Commenters stated that while EPA has provided flexibility in the compliance measures allowed, these options may not be sufficient or cost

- effective compared to greater achievement of heat rate improvements at existing coal

- fired units when operated as designed to provide for base load power at higher capacity factors. Furthermore, c ommenters stated that the interim goals present challenges in the pace of this possible shift in generation resources potentially making it difficult to obtain regulatory approvals for heat rate improvements at existing coal

- fired EGUs post

- 2020. To that end, as proposed by EPA in the NODA, the commenters stated that it would be reasonable to address these concerns by allowing state agencies to take into account the book life of the original coal

- fired assets, as well as the book life of any major upgrades to the asset, such as major pollution control retrofits. Commenters suggested that states should be provided the flexibility and option to use the book life (or some other reasonable measure such as depreciation schedule) as the basis f or the development of an alternative emissions glide path that would phase

- out these assets in a manner that maximizes emissions reductions while reducing impacts to reliability or affordability. At a minimum, commenters stated that the EPA's final rules m ust allow for states to consider the remaining useful life in demonstrating a request for a retirement off

- ramp on an EGU

- specific basis that could either revise the required emissions reductions or compliance deadline in the 111(d) plan.

Comment 7: Comme nters indicated that there may be a conflict with building block 3 (increasing RE capacity) and building block 2 (as RE increases, capacity factors for NGCC decrease) in relation to the 2012 baseline.124 Response 7: EPA disagrees with commenters suggesting t hat the building blocks 2 and 3 are in conflict

. See response at the beginning of the section for EPA’s response to these comments

. The following are summaries of the specific public comments under this comment:

Commenters stated that the most significant contributor to the emission reduction goal is the Block 2 re

- dispatch calculation. Commenters stated that in states with high levels of RE, NGCC capacity factors in 2012 were substantially lower; the NGCCs were used to balance the intermittent renewables o n the state electricity system. Commenters stated that because they had lower capacity factors in 2012 due to RE, these NGCCs drive the state to more stringent targets through the Block 2 calculation. Commenters stated that Block 2 acts to increase the com pliance burden on RE leaders and that EPA should address this by allowing states to recalculate the 2012 baseline by taking into account the effects of RE on NGCC capacity factors.

Comment 8: Several commenters indicated that there may be a conflict with building block 3 (increasing RE capacity) and building block 2 because as RE increases, the ability to re

- dispatch
to 70

- percent utilization of NGCC decreases.

Response 8: EPA disagrees with commenters suggesting that the building blocks 2 and 3 are in

co nflict

. See response at the beginning of the section for EPA’s response to these comments

. The following are summaries of the specific public comments under this comment:

Commenters stated that states with high levels of RE tend to have lower NGCC capacity factor because NGCCs are used to support variable RE generation. Commenters stated that EPA assumed this capacity would be available to support re

- dispatch. Commenters st ated that this assumption penalizes states that have invested in RE by imposing upon them more stringent goals based on higher amounts of re

- dispatch. Commenters stated that these states are further penalized because this NGCC capacity is not available for re

- dispatch, as it is needed to support RE generation.

Commenters stated that NGCCs are an important resource for balancing high levels of intermittent RE. Commenters stated that NGCCs are an important resource for balancing high levels of intermittent RE

. Commenters stated that because of the flexibility and dispatch characteristics of NGCCs, wind often tends to displace NGCC generation. Commenters stated that studies by MISO, ERCOT and NREL demonstrate that a significant portion of wind generation displa ces NGCC generation

-- from 32.6 percent in the MISO region, up to 83 percent in the West, and 87 percent in ERCOT. Commenters stated that an internal analysis conducted by Xcel Energy using historical data from four representative months showed that wind displaces NGCC about 39 percent of the time on the system of Xcel Energy's Colorado affiliate, Public Service of Colorado ("PSCo").

Commenters stated that wind/NGCC "displacement factors" demonstrate that NGCCs in states with high wind penetration have a l ower capacity factor due to the operation of wind generation in those states and their utility systems. Commenters stated that the 2012 baseline NGCC capacity factors used in EPA's Building Block Two methodology therefore were lower in states125 with signific ant RE than they would have been absent these pre

- 2012 RE investments. Commenters stated that because the amount of NGCC generation assumed to displace coal and oil/gas steam generation depends on the difference between actual 2012 capacity factors and the 70 percent capacity factor target, this leads to more stringent Building Block Two calculations and emissions targets in states with high amounts of RE.

Commenters stated that the addition of RE likely will require increased use of natural gas units for back

- up and ramping, which could be incompatible with EPA's proposed 70

- percent utilization rate for existing NGCC units. Commenters stated that these units cannot both run at high utilization rates and simultaneously be available to support variable renew able generation. Commenters stated that because the output of renewable resources is variable, use of these resources requires balancing and back

- up services from the grid. Commenters stated that natural
gas

- based units are more flexible than other fossil fuel

- based dispatchable resources and usually provide these services. Commenters stated that units needed to back up variable resources operate at lower capacity factors so that they can respond to a relatively sudden or unplanned decrease in electric gene ration at any time by increasing output. Commenters stated that increasing the utilization rate of the existing NGCC fleet to 70 percent reduces their availability to back

- up renewables. Commenters stated that increasing renewable generation could mean tha t existing NGCC units may need to reduce their capacity factor to increase their responsiveness to the variability of renewable output. Commenters stated that increased utilization of NGCC unit generation could limit the ability to integrate additional ren ewables into the grid unless other resources are added.

Commenters stated that these interrelationships undermine EPA's assertion that the desired level of re

- dispatch will occur within the existing NGCC fleet and that no new power plants would be needed. Commenters stated that variable renewable resources could also be supported by existing simple

- cycle CTs, which would need to operate at higher utilization rates. Commenters stated that because CTs are less efficient than NGCCs, this would tend to increas e the overall CO2 emissions rate and hamper states in their efforts to meet their overall emission reduction goals.

Commenters stated that building Block 2 effectively reduces a system's turndown (cycling) capability by requiring NGCCs to operate up to a 70 percent capacity factor, at the same time Building Block 3 increases the need for nimble generation resources to serve ramping and regulation needs due to the significant addition of intermittent renewable resources. Commenters stated that as proposed, the interaction of Building Blocks 2 and 3 will increase generation costs, reduce reliability, and hinder system planning. Commenters provided a figure, data, and cited other reports to support this claim. Commenters stated that increased renewables will w ork against EPA's goal of achieving a 70 percent NGCC fleet

- wide capacity factor regardless of natural gas prices.

Commenters stated that EPA assumes that high levels of NGCC unit utilization in Building Block 2 can be achieved and maintained concurrently with increased deployment of renewable generation through Building Block 3, despite the fact that natural gas

- based generation is often required to cycle to support the integration of variable and intermittent renewable126 Commenters stated that BB3 requires more capacity to be available to respond to the highly intermittent resources. Commenters stated that this load

- following capacity has historically been gas, but operating gas units to load

- follow reduces their capacity factors and severely curtails their ability to meet building block 2 goals. Commenters stated that EPA claims to have demonstrated that the emission reductions achieved by each building block are independently attainable, and therefore can simply be added together to determine an overall go al. Commenters stated that under the CAA, it is EPA's burden when determining BSER to show that the building blocks, applied simultaneously and in concert, are "achievable" and have been "adequately demonstrated" for each state. Commenters stated that EPA has failed to make this demonstration. Commenters stated that prior to finalizing the rule, EPA must present analysis or modeling that shows the reductions that can actually be achieved when implementing all four building blocks simultaneously for each sta te, as well as nationally.

A s illustration of the interplay between the building blocks, commenters stated that Emery Generating Station's capacity factor is significantly influenced by the strong wind regime in Iowa (i.e., the company has seen low combined cycle capacity factors due to the concentration of wind energy nearby). Commenters stated that this is an example of an efficient NGCC that cannot run more because of transmission constraints. Commenters stated that existing transmission in Emery' s area will not disperse all of the wind around the Emery Generating Station, so it cannot run as much as it otherwise could. Commenters stated that while transmission projects are currently planned that are intended to remedy the situation, the continued integration of renewables could lead to similar situations where the transmission system may not be able to reliably and cost

- effectively support high capacity factor gas and high capacity factor renewables at the same time.

Commenters noted that in its BS ER analysis, the EPA determined "achievable" levels of implementation for each individual Building Block in isolation. Commenters stated that the EPA has not considered the impact of each of the four Building Blocks on the electric system as a whole, nor h as it examined how the Building Blocks will interact with or affect the achievability of the others. Instead, the commenters stated that the EPA concluded that reaching the prescribed levels of each of the Building Blocks is possible separately and, hence, also simultaneously which the commenters asserted is unlikely.

Commenters stated, for example, there is a direct interdependency between variable renewable generation and natural gas units. Commenters noted that because the output of renewable resources i s variable, use of these resources requires balancing and backup services from the grid. Commenters stated that natural gas

- based units are more flexible than other fossil

- fuel

based dispatchable resources and usually provide these services. Commenters sta ted that units needed to back up variable resources operate at lower capacity factors so they can respond with increased output to a relatively sudden or unplanned decrease in electric generation at any time. Commenters stated that increasing the utilizati on rate of the existing NGCC fleet to 70 percent reduces their availability to backup renewables and complicates the ability to comply with NERC reliability standards while integrating renewables. Moreover, the commenters stated that increasing renewable g eneration could force existing NGCC units to reduce their capacity factor in order to ensure responsiveness to the variability of renewable output. Alternatively, the commenters stated that increased utilization of NGCC unit generation could limit the abil ity to integrate additional renewables into the grid unless other resources are added. Commenters127 concluded that these interrelationships undermine EPA's assertion that the desired level of re

dispatch will occur within the existing NGCC fleet and that no new power plants would be needed.

Commenters stated that power plants are designed and built with specific characteristics and are able to achieve maximum efficiencies under particular circumstances. Commenters stated that if increased renewable generatio n results in more cycling of NGCC units, their technical efficiency likely will be degraded, increasing the emissions rate of the unit and that of the entire system. Commenters stated that increased cycling, more startups and lower capacity factors increas e the emissions rate of power plants.

Commenters requested that the EPA consider the economic impacts of NERC reliability standards as they relate to backing up wind and other intermittent resources. Commenters recommended that Colorado and Wyoming state g oals should be adjusted to acknowledge such realities of managing the bulk electric system.

Commenters stated that it is unknown, and EPA has not analyzed, how the implementation of other building blocks will impact the goal of achieving 70 percent capacit y factors for NGCC units. Commenters provided, as an example, more renewable generation will require more back up generation, leading to increased cycling of natural gas fired units. Commenters stated that increased cycling will likely result in a decrease in unit efficiencies as utilities attempt to balance the randomness of renewable generation. Otherwise, commenters stated that to maintain a 70 percent capacity factor, cycling would likely be required by coal units or new simple cycle gas turbines.

Comme nters stated that Building Block 3 may run counter to maintaining a high utilization rate at natural gas plants. Commenters stated that renewable energy suffers from intermittent generating capacity, as a result of near

- constant variation in sunlight and w ind availability. In order to maintain grid reliability, commenters stated that natural gas plants are needed on standby to fill

- in for tapering renewable energy generation. Commenters stated that if all natural gas plants are instructed to maintain a high utilization rate, there may be insufficient spare capacity to fill

- in for intermittent renewables. As a result, commenters argued that then EPA is incorrect to assume that the emissions reductions that would occur as a result of Building Blocks 2 and 3 ar e additive. Rather, commenters stated that the two numbers overlap to a significant extent, and the EPA should adjust Indiana's state emissions targets accordingly.

Comment 9: Commenters discussed impacts associated with electricity generation from natural gas and natural gas consumption

. Response 9: EPA thanks the commenters

. See Preamble Section V.A for treatment of new NGCC under BSER

. See also chapter 3 of the final rule Regulatory Impact Analysis for discussion of the impact of the rule

.
The f ollowing are summaries of the specific public comments under this comment:128 Commenters stated that one outstanding question is whether states can build new natural gas

fired power plants to meet their carbon

- reduction targets under the Clean Power Plan. Com menters noted that the EPA writes that new NGCC capacity "cannot be directly counted towards the average emissions rate" used for state compliance with the target, but it "can displace some generation from covered sources and thus indirectly lower the aver age emissions rate from covered sources." (RIA, p. 2

- 35) Commenters noted that the EPA requested public comment on this matter, asking "whether we should consider construction and use of new NGCC capacity as part of the basis supporting the BSER."

Comment ers stated that if the EPA chooses to count construction of new NGCC units as part of the best system of emissions control, states may have additional incentive to invest in new natural gas generation capacity. Commenters stated that it is unclear whether this investment would come at the expense of investment in cleaner energy technologies.

Commenters stated that implementing building block 3 will bring more renewable energy capacity online and displace generation from more carbon

- intensive fossil

- fuel

- fir ed plants. Commenters stated that implementation of the energy

- efficiency measures in building block 4 will reduce economy

- wide electricity demand by 11 percent from the base case level by 2030. (RIA, p. 3

- 26 and 3

- 36) Commenters stated that less electrici ty generation translates into lower natural gas use. Commenters stated that the EPA notes that if states implement the clean energy and energy efficiency policies in building blocks 3 and 4 more quickly than the Clean Power Plan suggests, then the projecte d rise in natural gas use could be mitigated even more. Commenters stated that this is consistent with other studies showing that renewable energy and energy efficiency can displace natural gas

- fired electricity generation and curb natural gas demand.

Co mment 10: Commenters noted that all four building blocks overlap within the interconnected power system.
Response 10: EPA agrees the building blocks overlap, in the sense of interacting in the interconnected power system, but disagrees that this overlap h as not been adequately assessed

. See response at the beginning of the section for EPA’s response to these comments . Also see final rule Regulatory Impact Analysis, chapter 3.

The following are summaries of the specific public comments under this comment:

Commenters stated that because the Building Blocks are part of an interconnected power system, they need to be evaluated jointly. Commenters stated that EPA did not consider these interactions, which tend to limit the reduction potential of each Building Block when compared to EPA's assessment of the Building Blocks in isolation. Commenters stated that if EPA relies on the interconnected power system as the basis for the BSER determination, the Agency cannot ignore these interactions when projecting the reductions achievable through each of the Building Blocks. Commenters stated that the Agency should consider this issue before finalizing the st ate

specific emission rate goals and that EPA's final state goals also should reflect the operational reliability needs of the interconnected power system as they currently are understood.129 Commenters indicated that EPA’s reduction goals may be overstated, because they do not account for the fact that the four building blocks interact in an interconnected power system, which limits the reduction potential of each Building Block

.
Commenters stated that t he EPA used building blocks to calculate each state's carbon reduction goal and, in so doing, has made each building block legally severable from the others. Commenters stated that t his is not the way that an integrated electric system operates and that in order to have a reliable, efficient, and reasonably p riced electric system, the inter

- relationship between each building block, along with transmission system constraints, must be considered as an integrated whole.

Comment 11: Commenters stressed that the order in which the building blocks are applied needs to be considered in EPA's analysis

. Response 11: EPA has appropriately considered the order of the building blocks

. . See the Goal Setting TSD and response at the beginning of this section.

The following are summaries of the specific public comments under this comment:

Commenters stated that if NGCC units are re

- dispatched to a capacity factor of 70%, as assumed by the EPA, the role of these units will essentially shift from load

- following, intermediate resources to base load resources. However, commenters noted that the need for load

- following resources will not be eliminated as a result of the rule, but will increase due to the increase in renewable penetration assumed in Building Block 3. Commenters stated that if NGCCs become base load resources, the in termediate load role will likely be taken up by a combination of coal units operating at reduced loads and/or simple cycle peaking units operating at increased capacity factors. Commenters stated that this increased cycling and reduced coal unit capacity f

actors will in effect negate the technical feasibility of EPA's assumed Building Block 1 heat rate improvements by potentially resulting in degradation of efficiency gains

. To remedy this, commenters stated that the EPA's final guidelines cannot determine the levels for each Building Block in isolation. Rather, commenters stated that the EPA must not only consider the relative contribution of each Building Block holistically, it is also relevant to consider the order in which they are applied in the goal c omputation. For example, commenters stated that it makes no sense that EPA applied heat rate improvement in Block 1 then subsequently applied this lower CO 2 rate to reduce coal

- fired generation in Block 2. Commenters stated that the EPA should have applied Block 2 to increase NGCC dispatch then applied coal plant efficiency at the reduced load factors applicable to these units. Commenters referred to additional technical analysis provided in EPRI's public comment submitted on October 20, 2014 (pages 29

- 35 ), demonstrating that since the EPA target rate is a fraction (i.e., lbs/MWh) the contribution of each building block to making up the target rate depends crucially on the order in which the building blocks are added.

Therefore, commenters concluded that the EPA's final guidelines for the Clean Power Plan must consider the impact of the four BSER building blocks on the electric system as a whole, as well130 as examine how the individual building blocks will interact with or affect the achievability of each ot her.

Comment 12: Commenters stated that the IPM modeling should consider interactions in the building blocks and system as a whole.

Response 12: EPA disagrees

. EPA has adequately treated considered the interactions, and additional modeling with IPM is not needed

. See response at the beginning of the section for EPA’s response to these comments

. The following are summaries of the specific public comments under this comment:

Relative to the NODA, commenters stated that the EPA must determine the require ment for each state based on evaluating the interactions of the building blocks and the response of the electric generation system as a whole. Commenters stated that this is necessarily an iterative process where the interaction of the building blocks will inform adjustments to the final determination of achievable building blocks for each state. Commenters noted that in the past, EPA used the Integrated Planning Model (IPM) to perform such evaluations, including development of the proposed CAA section 111( b) NSPS standards. Commenters stated that the IPM model is not a perfect tool that identifies all issues and constraints, but it will provide a more comprehensive representation of the collective impacts caused by the interactions of the proposed building block. For this reason, commenters stated that the EPA will also have to consider adjustments to the IPM results raised by each state.

Commenters stated that building block 2 should not be based on an arbitrarily

- applied generation offset to each state, b ut instead should be based on what has been demonstrated to be achievable in each state at existing NGCC units. Commenters stated that the IPM model should then be run based on these NGCC capacity factors for each state. Commenters noted the model will re

dispatch generation through the grid, regardless of state or regional boundaries, based on cost

effectiveness and taking into account available generation resources. Commenters noted that this same exercise applies to establishing EE and RE offset of other generation resources.

In addition to the interaction of the building blocks, commenters stated that modeling accounts for electricity growth, nuclear plant retirements, and the real operation of the electric system. Commenters suggested that modeling shou ld also reflect constraints identified in their comments, including keeping major coal

- fired EGUs with major investments in operation and maintaining coal

- fired EGUs at capacity factors of 50% annually or greater to avoid efficiency losses. Commenters stat ed that the results of this system

- wide modeling, for all building blocks together, should then be used to inform how generation will move among states, what generation and emissions are offset by the building block requirements, and finally the resulting emission targets in each state. Commenters noted that this is similar to how EPA established state emission budgets under the Clean Air Interstate Rule (CAIR) and the Cross

- State Air Pollution Rule (CSAPR).131 Comment 13: Commenters suggested that NGCC units degrade more rapidly when cycled frequently

. Response 13: EPA disagrees

. Although it is true that greater cycling affects the operation of NGCCs, the rule is not expected to lead to greater cycling. For issues and studies related to RE and NGCC see GHG M itigation Measures TSD, Chapter 4

. The following are summaries of the specific public comments under this comment:

Commenters stated that power plants are designed and built with specific characteristics and are able to achieve maximum efficiencies under p articular circumstances. Commenters stated that if increased renewable generation results in more cycling of NGCC units, their generation efficiency likely will be degraded, increasing the emission rate of the unit and that of the entire system. Commenters stated that a recent North American Electric Reliability Corporation (NERC) and California ISO study (2013 Special Reliability Assessment) concluded that increased supply variability introduced into the electric system associated with significant penetrat ion of variable renewable generation will cause more frequent dispatches and the starting and stopping of flexible, gas

- based generators, which will potentially incur more wear and tear. Commenters stated this wear and tear has the potential to degrade hea t rates and increase emissions. Commenters stated that there is little data that addresses the possible magnitude of the degradation of a new unit's heat rate over time as it is required to cycle ever more frequently to accommodate renewables integration.

Comment 14: Commenters supported consideration of all four building blocks together to represent aggregated system emissions

. Response 14: EPA agrees and thanks the commenter for this comment

. The following are summaries of the specific public comments under this comment:

Commenters stated that the BSER as determined by EPA reflects that individual generating units do not operate independently, but are instead part of a system of highly interdependent sources whose aggregate emissions are dependent on sy stem management. Commenters stated that states, electricity system operators, and power companies are achieving carbon pollution reductions from fossil fuel

- fired power plants by shifting the grid as a whole away from high

carbon power sources. Commenters stated that on

- the

- ground experiences demonstrate that a combined approach using all of the strategies reflected in EPA's four building blocks is the most
cost

- effective way to achieve reductions from the energy sector. Commenters provided numerous citatio ns to support this claim, specifically detailing the accomplishments achieved under RGGI, Minnesota's clean energy and emissions reduction programs, and California's comprehensive efforts to reduce greenhouse gas emissions.

Comment 15: Commenters favored use of all four building blocks as opposed to considering only building blocks 1 and 2.132 Response 15 : EPA appreciates this comment

. EPA has revised the building blocks in the the final rule

. See section V.A of the final rule preamble of the CPP for the EPA’s response to this
comment.
The following are summaries of the specific public comments under this comment:

Commenters responded to EPA's invitation to comment on a BSER composed only of heat

- rate improvements to coal

- fired EGUs (building block 1) and dispatch to existing combined

- cycle natural gas EGUs (building block 2). Commenters stated that a system composed only of these two building blocks would provide less overall opportunity for carbon pollution reduction at a higher cost. Commenters stated th at reducing demand for fossil generation or providing alternative, cleaner sources of supply achieves emissions reductions far beyond the level that can be achieved by improving the operations of individual fossil plants and shifting to natural gas. Commen ters stated that reductions from demand

- side energy efficiency and renewable energy are also among the most cost

- effective reductions. Commenters stated that a more limited system would not promote the most cost

- effective carbon reducing improvements to th e power sector, and therefore cannot be considered the best system of emission reduction.

Commenters stated that when determining the best system of emission reduction, EPA is directed to consider that Section 111 is designed to promote the development an d implementation of technology. Commenters stated that including in the BSER the opportunities available throughout the electricity system to reduce emissions from affected sources will promote technological advancements throughout the sector that will dri ve further carbon reductions. Commenters stated that a system limited to only building blocks 1 and 2 would exclusively promote improvements of fossil fuel

- fired technologies, but would not promote technological improvements or increases in deployment of z ero

- carbon generation or advanced technologies to reduce energy demand. Commenters stated that it is these latter elements of the system that will be most critical to achieving the long

- term carbon pollution reductions in the power system necessary to addr ess the challenge of climate change.

Commenters noted that state experience demonstrates that the combination of heat rate improvements in fossil

- fired EGUs, shifts in dispatch to less carbon

- intensive generation sources, and reductions in fossil

- fuel fir ed generation from increased zero

- carbon and low

carbon generation and increased demand

- side efficiency, as reflected in building blocks 1 through 4, achieve a high degree of cost effective carbon emissions reductions. Commenters stated that the emissions reductions they have achieved are significantly greater and more cost effective than could be achieved by heat rate improvements and re

- dispatch alone. Commenters stated that the BSER should be composed of the entire system reflected in all four building b locks.

Comment 16: Commenters addressed interactions in building blocks 2

- 4, and stated that the sum of the implied CO2 emission reductions in Blocks 2

- 4 exceeds the total 2012 coal generation with which EPA begins its emissions limits calculation.133 R esponse 16: EPA disagrees

. This rule will not force coal to “effectively zero” as the commenter claims, but leaves a significant role for coal

. See the RIA and the response to at the beginning of this section.

The following are summaries of the specific pu blic comments under this comment:

Commenters stated that they are concerned that Rule 111(d) may effectively force coal generation to essentially zero. Commenters stated that Block 2 requires a 72 million MWh reduction in annual production from coal plants in calculating emissions limits. Commenters stated that Block 3 then requires a 54 million MWh increase in renewable energy. Commenters stated that w hile this increase in renewable energy would normally reduce natural gas fired electricity, such a result would cause Texas's average emissions rate to rise. Commenters stated that Block 4 further requires a 38 million MWh reduction in total energy use through the energy efficiency calculation. Commenters stated that most efficiency programs reduce marginal en ergy consumption/generation which would be natural gas

- fired units in normally functioning competitive markets; however, this outcome would also cause Texas's emission rate to rise necessitating further coal generation decreases. Commenters stated that the sum of the implied CO 2 emission reductions in Blocks 2

- 4 exceeds the total 2012 coal generation with which EPA begins its emissions limits calculation

. Commenters stated that application of Block 2 essentially contemplates that coal fired power plants will operate in a ramping mode, or will be entirely shut down and unavailable during long periods during the year. Commenters stated this ignores the realit y of the needs for changing amounts and types of electric generation during the day. Commenters provided figures to illustrate seasonal load profiles experienced in Texas (figures 5 and 6):

• Figure 5 is a typical August day in Texas. The ERCOT load almost doubles on a summer day, increasing from about 36,000 MW to over 68,000 MW. Simply put, during Texas' (and other states') peak demand days, all available generation must be running in a reliable fashion. That means coal plants must run consistently around the clock due to their inability to effectively ramp to meet customer demand.

• Similarly, Figure 6 is a typical spring or fall day and shows how low the load in ERCOT typically can dip in the spring or fall. Texas must have a balanced, diversified generatio n mix in order to be able to start up generation facilities as load climbs, and then be able to ramp them down as load declines.

• Figure 6 demonstrates a different problem that can occur with too much renewable generation as Rule 111(d) seeks to mandate thr ough application of Block 3. Between 3:00 a.m. and 6:00 a.m. electricity consumption can drop below 25,000 MW. ERCOT previously has experienced days in which wind has provided as much as 38.4% of the generation on the system. Rule 111(d) fails to acknowled ge this reality through its use of Block 2's methodology, which creates both practical difficulties and perverse results. Wind turbines in Texas typically have a much higher capacity factor during spring and fall months. During the spring and fall a 20% re newable energy goal as proposed by EPA under Block 3134 could put more renewable generation on the grid than there is existing load. Consequently, during the early morning hours ERCOT would have to both curtail a substantial amount of the wind and back down o r even shutdown much of the nuclear fleet and all other thermal generation, which would simultaneously reduce the effectiveness of both Block 2 and Block 3. As has been previously shown, coal plants cannot effectively operate in a manner that would have th em ramp up and down to meet load.

Commenters stated that blocks 2 and 3 yield a paradox as well, working at cross purposes in a diversified, efficient market (like ERCOT). Commenters provided figures showing the high variability of wind (figures 7 and 8 ). According to the commenter s :

• On the day referenced in Figure 7, wind generation dropped 93% (a total loss of 6,500 MW) over 13.5 hours. An over reliance on wind coupled with a possible 93% reduction of wind generation on any given day mandates an increased reliance on flexible gas generating units and less on base load units to ensure system reliability and sufficient availability of power. This introduces enormous costly redundancies into ERCOT's system and likely means that nuclear generating units will b e backed down when it is windy, only to be replaced with combined cycle or simple cycle gas turbine units. Because significant variability of wind and other renewable generation can occur rapidly, within minutes, ERCOT's nuclear fleet cannot respond effici ently because the units are not designed for load following operations.

• An example of what the ERCOT generation mix must be able to handle over very short periods of time is shown in Figure 8.

• On May 7, 2013, ERCOT experienced three cycles of fluctuations in wind generation between 2,000 and 8,000 MW over a 14 hour period. This is equivalent to having 1,500 MW of thermal generation trip off line three times in 14 hours. Flexible natural gas

- fired generation is capable of matching the variability of wind and other renewable generation best due to its ramping ability; however, even gas combined cycle generation is most efficient when operated at or near 100% capacity.

Commenters stated that block 2 also effectively assumes that coal plants would be unavailable to operate during the winter months, when the risk of natural gas curtailments due to cold weather is highest. Commenters stated that this scenario presents serious reliability problems in the event of a cold weather event such as the one that occurred in Texas in February 2011. Commenters stated retirement of 10,000

- 12,000 MW of coal units by 2020 would present serious and immediate resource adequacy problems for ERCOT.

Comment 17: Commenters indicated that there may be a conflict with building block 2 ( re

dispatch to NGCC) and building block 3 because over reliance on natural gas could be detrimental to RE implementation.135 Response 17 EPA disagrees with commenters suggesting a conflict between NGCC dispatch and building block 3

. See response at the begin ning of the section for EPA’s response to these
comments

. The following are summaries of the specific public comments under this comment:

While natural gas will play an important role in the transition to a clean energy future, commenters urged the EPA to ensure that its final rule does not require or incentivize states to

over

- rely on natural gas. Commenters stated that an over

- reliance on natural gas in the near term will incentivize significant natural gas infrastructure build out over the next few years that will undermine the EPA's long term carbon reduction goals. Commenters stated that once the infrastructure is built, it will be more difficult and expensive for states to switch to lower and

non

- emitting sources like renewable energy in the future.

Co mmenters urged EPA to consider the impact of its rule on the build out of natural gas infrastructure. Commenters stated that affected EGUs may be incentivized to build significant natural gas infrastructure that will be in place for the next 20

- 30 years on ce constructed. Commenters stated that this could potentially discourage states from relying on renewable energy resources as a compliance option. Commenters stated that significant build out of natural gas infrastructure over the next few years could nega tively impact ratepayers in the long run if such infrastructure becomes stranded assets as carbon emissions become more expensive in the future. Commenters stated that natural gas is subject to extreme price volatility, such as was experienced by ratepayer s during the 2014 polar vortex.

Commenters noted that states may be incentivized to construct new natural gas plants that are not subject to 111(d) to avoid 111(d) requirements on affected EGUs. Commenters stated emissions that result from substituting gen eration by affected EGUs should be calculated toward a required emission performance level for affected EGUs meaning that if new natural gas plants are used for compliance purposes, they should be factored into the establishment of state targets to maintai n symmetry between the resources considered in setting the target and resources allowed for compliance. Commenters stated that treating new gas generation as if it has zero carbon emissions would result in less overall carbon emission reductions because th e gas generation would be subject to the cap under 111(d). Commenters stated that this would allow a state to treat new gas facilities as if they were zero

- emitting resources, creating a disincentive to rely on renewables or existing natural gas that is su bject to 111(d) regulations.

Commenters noted that the agency requests comment on how emissions changes under a rate

based plan resulting from substitution of generation by new NGCC for generation by affected EGUs should be calculated toward a required emi ssion performance level for affected EGUs. Commenters stated that the EPA should craft a final rule that allows states to avoid unnecessary costs by encouraging energy diversity and recognizing the long term price certainty and emission reduction value pro vided by renewable energy.

Comment 18: Commenters addressed re

- dispatch of coal and gas units within entities that operate across state lines.136 Response 18: EPA appreciates this comment

. The final rule no longer bases goal on in

- state shifting between coal and NGCC, but on interconnection wide generation shifting

. See Preamble Section V.

The following are summaries of the specific public comments under this comment:

Commenters stated that TVA generates power from fossil fuels in 4 states and distribut es power to Tennessee and portions of 6 other states. Commenters stated that it also buys and sells some power from neighboring systems, and optimizes the dispatch of generating assets and operation of transmission infrastructure as a system to maintain re liability and minimize cost. Commenters stated that EPA's analysis assumes increasing NGCC generation in a state will displace coal generation in that same state. Commenters stated that this would be a valid assumption if the transmission infrastructure wa s in place to allow the NGCCs to meet the load centers served by the displaced coal generation and the state's generating units were dispatched as one system confined within the state. Commenters stated that this is not the case with TVA's NGCC units in Mi ssissippi. Commenters stated that three of TVA's five NGCC plants are located in Mississippi, but all of its coal fired units are located outside of Mississippi (TVA does purchase power through a power purchases agreement from the Red Hills coal

- fired unit in Mississippi). Commenters stated that increasing the capacity factor of TVA's Mississippi NGCC plants would have minimal effect on coal fired generation in Mississippi that is operated to serve the demand for electricity in Mississippi. Commenters state d that virtually all of the generation displaced would be from TVA's coal

- fired units in other TVA states.

Comment 19: Commenters noted that the electric markets relevant for building blocks 3 and 4 do not operate on a state

- by

- state basis, and suggested that states should be provided broad flexibility on counting future renewables and energy efficiency towards compliance.

Response 19 : EPA appreciates this comment

. The final rule no longer bases goal on in

- state shifting, but on interconnection wide gener ation shifting

. See section V of the final rule preamble.

The following are summaries of the specific public comments under this comment:

Commenters noted that the EPA states in the rule that there must be a correlation between CO2 reductions and adding renewables and energy efficiency. Commenters stated that the EPA's requirement that states prove certain fossil EGUs in a state weren't dispatched as a result of energy efficiency or renewables is inconsistent with how Western energy markets operate. Comme nters stated that adding renewables and energy efficiency may at first blush seem like an effective way to reduce emissions from thermal plants in a state but energy markets are much more complex. Commenters noted that generation dispatch isn't controlled by a state regulator. Commenters noted that market price, transmission path constraints, NERC reliability mandates, local air emission constraints and balancing authority operations drive whether generators dispatch in a given state to support loads somewh ere else in the WECC, not in a specific state. Commenters stated for example there are significant time periods when gas CCCT generation in Washington does not need to be dispatched to meet loads within the state (which can be met with137 largely instate hydr oelectric generation), but are needed to support high summer demand in Southwestern regional markets.

Commenters stated that the wholesale energy markets are regulated by FERC, not the states. Commenters stated that FERC has adopted numerous major policy c hanges in the past two decades to encourage greater open market functioning of these wholesale markets. Commenters stated that reliability of the entire grid depends on all the resources and loads connected to it, and the regulated wholesale markets determ ine how those generators will be dispatched. Commenters stated EPA's requirement that states show a link from renewables and energy efficiency to reduction of CO2 emissions is inconsistent with how FERC regulates wholesale markets.

Commenters explained tha t asking the State of Washington to prove why a generator it doesn't own did or did not dispatch in such a large, complex market is not feasible, as illustrated by the following points:

• In 2013, there was approximately 215,000 MW of generation in the WECC ; about 70,000 MW of that was fueled by natural gas. In the context of this market place, the affected EGUs in Washington are only about 4,700 MW, about 3,200 MW of which are gas

- fired.

• Across the 70,000 MW of gas plants in the WECC, each of those natural gas EGUs have different efficiency rates for converting natural gas to electricity. Each has unit

- specific air emission constraints and there are at least seven different gas hubs from which natural gas can be acquired depending on where the plants are loc ated.

• Furthermore, transmission capacity to allow generation in one area to support loads in another is constrained

- and those constraints change as generation and loads change throughout each hour.

Commenters stated that it is difficult to directly link a n increase in MWh of renewable energy to a decrease in MWh in any plant, or even fossil fuel in general, during any specified time period. Commenters provided for example, if the wind blows all spring when thermal plants likely won't run, the generation of fset is likely regional hydro. Commenters noted that the Bonneville Power Administration (BPA) has several charts showing thermal plants on their system running flat through the day as the wind ramps and descends intra

- and inter

- hour; hydro is what is oft en being impacted.

Commenters stated that power plants in the WECC are integrated into a vast market, not dispatched on a state

- by

- state basis. Commenters stated that there are more than 35 individual balancing authorities in the WECC, which includes 200,0 00 MW of generation, interconnected on a vast and complicated transmission network. Commenters explained that this means installing renewable generation in one state may or may not affect thermal plant generation in that state

- and there may be times when r enewable generation won't offset any thermal generation at all because electric markets simply do not operate on a state

- by

- state basis.138 Commenters addressed the complexity of enforcement of Block 3. Commenters stated that demonstrating that renewable ener gy reduced the dispatch of an in

- state resource, or any EGU, will render this aspect unworkable. Commenters noted that if the State desires to retain emission rate targets using building Block 3, compliance will have to be so simplified that achieving the emission rate target may not end up reducing CO2 emissions from EGU's at all

- missing the entire purpose of the rule.

Commenters stated that while there is a more logical connection between many energy efficiency measures and the need for resources it is still difficult to tie to a specific emission reduction at an EGU

. Commenters stated that if Block 4 is initiated, they support counting all types of energy efficiency programs and measures towards the goal (as verified by the state), and energy efficiency savings do not have to be tied to a reduction of emissions at a specific EGU.

Commenters stated that any change to EPA's building blocks needs to be followed by a change and adjustment to the state goals. Commenters stated that if Building Blocks 3 and 4 include a look

- back for compliance they need to be reevaluated according to what emission reduction can be correlated and reduced accordingly. Instead, commenters encouraged the EPA to drop the entire look

- back for compliance. If using a ratio, commenters suggested a state should just verify the amount of MWh in the building blocks of the denominator and the CO2 emissions by affected generating units in the numerator. Commenters argued that the EPA should either drop renewables and energy efficiency as buil ding blocks or fully count any additions towards compliance regardless of proven reduction of CO2 emissions.

Comment 20: Commenters addressed application of the four building blocks in Wyoming indicating that it is uncertain how RE and EE can be implement ed.

Response 20: EPA disagrees with these comments

. See section V of the final rule preamble of the CPP for the EPA’s treatment of the Building Blocks in the final rule . See also VIII on State Plans

. For the interaction of the building blocks, see also the response at the beginning of this section.

The following are summaries of the specific public comments under this comment:

Commenters stated that they are confused by the proposal to explicitly replace fossil generation by anticipated RE and EE. Commen ters stated that reducing Block 1 generation by Block 2 re

dispatch made sense because the displacement was essentially of a like kind, and gave every appearance of taking place before 2020. Commenters stated that such an explicit displacement

was necessar y in order for EPA's proposal to be something other than an irrational command to flood existing markets with new, more expensive generation. Commenters stated that the majority of RE and EE effects take place during the ten year glide path, and the majori ty of EE savings may well be deemed savings. Commenters stated that EE programs in which a utility exercises direct control, such as cycling of air conditioning when needed, do not exist in Wyoming. Commenters stated that they believe RE and EE effects to be more speculative in their implementation.139 Comment 21: Commenters addressed shortfalls in building blocks

. Response 21: EPA disagrees with these comments

. See response at the beginning of the section for EPA’s response to these comments

. The following are summaries of the specific public comments under this comment:

Commenters stated that proposed reductions in Building Blocks 1 and 2 do not appear achievable. Commenters stated that it is assumed that short falls in Building Blocks 1 and 2 would increa se the reductions required from Building Blocks 3 and 4. Commenters stated that this is without regard to technical or economic feasibility. Commenters stated that the USEPA must explain how shortfalls in some blocks affect targets in other blocks

.
Commenters stated that the Clean Air Act calls for BSER measures to demonstrate cost effectiveness under Section 111. Commenters stated that cost effectiveness for Blocks 2, 3 and 4 can fail under a BSER analysis if the overall stringency set for a Block t arget in a state cannot be cost effectively met. Commenters stated that EPA has indicated that a state may substitute additional action in one target area that offers lower cost compliance if the state encounters problems with the cost effectiveness of ano ther EPA set BSER target. Commenters stated that this sort of substitution of compliance measures is simply enabling an erroneous EPA BSER determination for a state to serve as a means for compelling additional state action in other BSER areas that were al ready indicated by EPA to have been structured near the threshold of cost effectiveness. Commenters stated that EPA should not penalize states by setting targets in a BSER Block too stringently.

Commenters stated that if a state determines that EPA establ ished a Block contribution to a target that is too aggressive to allow compliance within the state's cost effectiveness criteria, EPA should reduce the overall state target to the threshold at which the Block falls within the state's cost effectiveness cri teria. Commenters noted that the state can continue to utilize the flexibility for compliance that EPA indicated it intended by substituting more activity in Block areas that the state determines are both cost effective and able to bring compliance savings for the benefit of state electricity consumers.

Comment 22: Commenters addressed the potential for a shortfall in building block 1 in Virginia

. Response 22: EPA has revised the goal setting methodology in the final rule

. The CPP provides flexibility for how state choose to comply with the rule

. See Section VIII of the Preamble

. EPA disagrees with commenters that these building blocks cannot fully work together

. See response at the beginning of the section for EPA’s response to these comments

.
The fol lowing are summaries of the specific public comments under this comment:

Commenters stated that each building block must be justified on the technical achievability, availability, and cost of the measures within that building block, not on flexibility prov ided by other building blocks. Commenters stated that EPA's justification to overlook any technical or140 economic issues identified with each building block based on flexibility provided by the incorporation of other building blocks undermines the severabili ty of the individual components of the rule. Commenters stated that in Virginia, as well as other states with overly stringent targets, the proposed rule will require virtually full application of each building block to comply with the proposed state targe ts, rendering the supposed flexibility of compliance "illusory". Commenters stated that the ability to compensate for shortfalls in one (or more) building blocks through the use of the other building blocks is extremely limited. Commenters stated that an

u nrealistic 6% heat rate improvement assumption cannot be mitigated by over

- complying with an equally unrealistic energy efficiency goal.

Comment 23: Commenters addressed the potential for a shortfall in building block 1 in Arizona.

Response 23: EPA has r evised the goal setting methodology in the final rule

. EPA disagrees with commenters that these building blocks contain the alleged shortfalls

. See response at the beginning of the section for EPA’s response to these comments

. The following are summaries of the specific public comments under this comment:

Commenters stated that it is impossible to see how Arizona could meet the proposed carbon goals without re

- dispatching virtually all coal

- fired generation to NGCC. Commenters stated that the EPA has stat ed that Arizona may use other means of achieving the state goals in lieu of the

re

- dispatch of coal

- fired generation to NGCC (i.e., more RE and EE requirements).

Commenters stated that Arizona analyzed increasing RE and EE standards to allow for the conti nued operation of a portion of the coal

- fired fleet in Arizona and, in fact, these actions would have the opposite effect. Commenters stated that by increasing the RE and EE requirements to allow for the continued operation of some coal

- fired generation in meeting the final goal, the state actually moves further away from achieving compliance with the state's interim goal proposed by the EPA. Commenters stated that if Arizona designs its program to comply with the interim goal, the end result is a rate that is far lower than necessary to comply with the final goal, and a far smaller portion of the state's existing coal

- fired fleet is preserved.

Comment 24: Commenters stated that e xisting policies in Arizona are likely to contribute significantly towards Ari zona's emissions reduction goal and surpass EPA's expectations for Building Blocks 3 and 4.

Response 24: EPA has revised the goal setting methodology in the final rule

. The CPP provides flexibility for how state choose to comply with the rule

. See Sectio n VIII of the Preamble

. EPA disagrees with commenters that these building blocks cannot fully work together

. See response at the beginning of the section for EPA’s response to these comments

. The following are summaries of the specific public comments un der this comment:141 Commenters stated that there is a great deal of concern over Building Block 2, including the notion that EPA may be overestimating reduction levels achievable for Arizona. However, commenters stated that they have conducted some analysis suggesting that EP A may in fact be underestimating what is achievable for Building Blocks 3 and 4 under existing policies, which could offset a large portion of the need to re

- dispatch under Building Block 2. Drawing from data reported by the state's utilities, commenters s tated they believe that Arizona is on pace to significantly exceed the amount of renewable energy contemplated in the proposal under Building Block 3 which provides some flexibility within Arizona's other Building Blocks.

For Building Block 4, commenters stated that data suggest Arizona utilities will exceed the EPA's anticipated amount of energy savings in the early years. However, commenters stated that because the energy savings required by current state policies level off after 2020, Arizona may underp erform after 2022, unless policy changes are made. Commenters stated taken together, Arizona's existing policies, appear sufficient to achieve roughly half of the EPA's proposed goal through Building Blocks 3 and 4. Commenters provided figures to support t heir point (Figures 1

- 3).

Commenters urged ADEQ to conduct a robust scenario analysis that considers all the available options as ADEQ begins develop its State Implementation Plan. For example, commenters stated that their preliminary analysis suggests tha t the EPA's final and interim goals could actually be met without retiring a significant portion of Arizona's coal fleet. Provided that sufficient amounts of Building Blocks 3 and 4 are included, commenters recommended that ADEQ should evaluate different c ombinations of each Building Block, as well as other measures to determine the optimal outcome for the state.

Comment 25: Commenters addressed building blocks 1 and 2 in North Carolina.

Response 25: EPA agrees and thanks the commenter for the comment.

The following are summaries of the specific public comments under this comment:

Commenters stated that some individuals have argued that efficiency improvements cannot be achieved at coal plants in North Carolina if these plants are also being re

- dispatche d to natural gas under Building Block 2, and therefore operating at lower capacities. Commenters stated that this argument conflates the building blocks used to create North Carolina's target with the options available for compliance. In reality, commenter s stated that increases in generation from other electricity sources

- including and exceeding the limited increases envisioned by EPA's building blocks

- will allow older and less efficient coal units to retire. Commenters stated it is therefore mistaken to assume that inefficient coal plants will continue to operate at a low capacity and inhibit North Carolina's ability to reach its target.

Comment 26: Commenters stated that EPA should not assume improved heat rates from low

capacity coal units in New Yo rk.142 Response 26: EPA disagrees

. See the response at the beginning of this section.

The following are summaries of the specific public comments under this comment:

Commenters stated that there are flaws with the Building Blocks as they are applied to New Y ork that the EPA must address in order to produce reasonable CO2 emissions reductions targets. Commenters stated that these flaws are compounded by the manner in which the individual Building Blocks interact with each other and that they produce emissions reductions targets for New York that would compromise reliability if pursued on the timeline established under the Clean Power Plan. Commenters stated that New York's few remaining coal

- fired units effectively act as peaking units that are needed to meet p eak demand during relatively few hours of the year. Commenters stated that the likely result of Building Blocks 1 and 2, as applied to New York, would be that these coal

- fired EGUs would simply cease operating. Commenters stated that this would have a sign ificant adverse impact on reliability. Commenters stated that the EPA should not assume improved heat rates from coal units with very low capacity factors like those in New York.

Comment 27: Commenters believe that adding more energy efficiency is not cos t

- effective to reduce CO2; solar power is the preferred strategy to meet EPA’s CO2 targets.

Response 27: EPA thanks the commenter for the comment

. EPA agrees that solar power is an important RE source, however, EPA als o believes there are multiple cost effective pathways to compliance with the rule

. The following are summaries of the specific public comments under this comment:

Commenters stated that Florida Power and Light (FPL) has already proposed all the energy effic iency that would not adversely affect electric rates as part of its DSM Goals filing, and that FPL believes that adding more energy efficiency would not be a cost

- effective strategy to reduce CO2 emissions. Commenters stated that solar PV additions are exp ected to be the preferred strategy to comply with EPA's CO2 emission targets in the future. Commenters stated that FPL believes that its best approach

- and the one that will result in the lowest electric rates

- will be to add large

- scale solar PV generat ion as needed to meet the targets, even when such targets are based in part on assumed demand

- side energy efficiency.

Comment 28: Commenters believe continued operation of "at risk" nuclear units could become economically unfeasible.

Response 28: EPA has revised the approach to nuclear units in this final rule

. See Section V of the Preamble; also see the RIA, Chapter 3, for EPA’s analysis of the impacts of the rule

. The following are summaries of the specific public comments under this comment:143 Commenters stated that U.S. EPA included the generation of 6% of nuclear capacity to be "at risk," dispatched at a 90% capacity factor in the denominator of the goal calculation. Commenters stated that it is U.S. EPA's intention that the increased use of renewable fu els and the ambitious EE targets set forth in the proposed rule would serve to decrease demand. Commenters stated that they believe this will create a situation in which the continued operation of marginal or "at risk" nuclear units become economically unf easible. Commenters stated that if these units close, the generation of these units is likely to be replaced with additional generation from more carbon intensive sources, such as coal and natural gas. Commenters stated that urged U.S. EPA to examine more fully the interplay and potential counteractive results of greenhouse gas abatement measures when considered in totality as a BSER.

Comment 29: Commenters questioned the assumption that a shortfall in one building block can be compensated for through use of the remaining building blocks

. Response 29: EPA disagrees with this comment

. See response at the beginning of the section for EPA’s response to these comments

. The following are summaries of the specific public comments under this comment:

Commenters stated that the EPA assumes states can implement all Building Blocks, and that if a state cannot fully implement one Building Block, it can increase another. However, commenters argued that because most states cannot realistically implement at least one of the Building Blocks (e.g., because of the timing of installing new capacity) they have very limited ability to achieve EPA's goals. Commenters stated that this is exacerbated by EPA's faulty assumptions for many Building Blocks (e.g., assuming full capaci ty of units that are still under construction), eliminating any potential state flexibility in implementing the Building Blocks.

Commenters q uestioned the assumption that states can freely over

- comply with any of the building blocks to address any shortco mings in another block, the assumption that renewable energy production can increase and energy demand can decrease without displacing other generation, and the assumption that Section 111(d) authorizes EPA and states to re

- order the dispatch of coal

- and gas

- fired generators and impose new renewable energy, nuclear energy, and energy efficiency requirements.

Commenters asserted that states will likely not be able to achieve the goals set forth by the EPA in one or more of the building blocks. Commenters provided brief examples of why each building block could not be met (e.g., BB1 cannot be achieved by new coa l fleets, BB2 is constrained by gas supply and infrastructure, BB3 is difficult, and BB4 has already been done in many states). Commenters stated that EPA's assertion of flexibility is based on the false premise that each building block is attainable up to and above the amount established in setting the goal. Commenters stated that for each state that encounters a problem with any one of the building blocks, it must make up for that shortfall by overcompensating in another building block. Commenters stated that the most significant problems are likely to occur in those states that are expected to make the majority of reductions through BB2. Commenters stated that if BB2 compliance options are limited, states will have to find reductions through BB1 and BB3, which144 will be difficult given the time frame of the interim goal. Commenters stated that EPA has designed standards for many states that are simply unachievable in the allotted timeframe and that EPA needs to allow states to exempt certain facilities on a case by case basis as provided by the statute.

Comment 30: Due to displacing effects of RE/EE on fossil units, exact reliance on the four building blocks leads to over compliance.

Response 30: See section Vof the final rule preamble of the CPP for the EP A’s response to this comment and how BSER was developed for the final rule

. See section VIII for how states can implement the guidelines, and see RIA for estimates of the potential impacts of the final guidelines.

The following are summaries of the specifi c public comments under this comment:

Commenters stated that states retain the flexibility to determine the compliance path that makes the most sense under their unique facts and circumstances, so there is nothing requiring a state to follow the same path for compliance that EPA developed. Commenters stated that EPA does not take into account the displacement of NGCC and other fossil generation by new renewables and energy efficiency per Building Blocks 3 and 4. Commenters stated that these measures, which have zero fuel costs, would indeed displace fossil generation, which have fuel costs. Commenters stated that because of the displacing effects of renewables and energy efficiency on fossil units, exact reliance on the four building blocks (as used by EPA i n the target setting) would result in

over

- compliance. Commenters stated that this is an important reason to view application of the building blocks for target

- setting as distinct from their use for compliance. Commenters stated that it also shows that Ten nessee's route to compliance is less burdensome than a narrow focus on the target

- setting would indicate. Commenters stated that Tennessee's pursuit of measures under building blocks 3 and 4 will result in substantial carbon reductions, especially if those measures are allowed to displace fossil generation on a pro

- rata basis.

Comment 31: Inadequate BB 2 implementation timeline

Response 31: EPA has revised the timeline for the final rule

. See Preamble Section V and VIII.

The following are summaries of the specific public comments under this comment:

Commenters stated that the proposal that all of Building Block 2 would be implemented by 2020 departs from the approach to Building Blocks 3 and 4 which are proposed to be added gradually over the 2020

- 2030 comp liance period. Commenters stated that all of the measures included in Building Blocks 1, 2, and 3 require significant adjustments to electric supply, distribution, and consumption that require time and investment.145 Comment 32: Commenters stated m any of the proposed building blocks for compliance are incompatible simultaneously, and some of the building blocks may actually increase CO2 emissions.

Response 32: EPA disagrees with commenters suggesting the building blocks cannot interact as the commenter asser ts

. See response at the beginning of the section for EPA’s response to these
comments

. The following are summaries of the specific public comments under this comment:

Commenters argued that building blocks 1 and 2 are incompatible. Commenters noted that NE RC points out that building block 2 will cause coal units to cycle more often, making the heat rate improvements in building block 1 less likely.

Commenters stated that building blocks 2 and 3 also run counter to each other. Commenters noted that because w ind and solar power are intermittent, they require a backup source of power for when the wind isn't blowing and the sun isn't shining. Commenters stated that the EPA seems to envision natural gas as being that backup source of power, but building block 2 r equires natural gas to run at 70 percent capacity factor. Commenters stated that natural gas plants cannot simultaneously run at 70 percent and also serve as a constantly available source of backup power which can quickly ramp up and down to match demand. Commenters noted that NERC again points out the problems with EPA's assumptions, noting that building blocks 2 and 3 together harm the fuel diversity of base

- load sources.

Commenters stated that building block 3 is inconsistent with itself

- it essentially requires states to impose renewable portfolio standards. Commenters stated that nuclear power is a CO2

- free source of reliable base

- load electricity, but forcing too much wind and solar energy onto the grid can harm it. Commenters noted that energy and cl imate expert James Hansen points out the "nuclear

- killing" effect that renewables can have:

" The asymmetry finally hit me over the head when a renewable energy advocate told me that the main purpose of renewable portfolio standards (RPS) was to "kill nucle ar". I had naively thought that the purpose was simply to kick

- start renewables. Instead, I was told, because utilities were required to accept intermittent renewable energies, nuclear power would become less economic, because it works best if it runs flat out. What to do when the wind is not blowing? The answer was: have a gas plant ready as back

- up. In other words, replace carbon

- free nuclear power with a dual system, renewables plus gas. With this approach CO2 emissions will increase and it is certain th at fracking will continue and expand into larger regions ."

Commenters noted that with building block 3, the EPA claims to promote an expansion of intermittent wind and solar generation while simultaneously guaranteeing that these sources will not "cannibal ize" nuclear power

. Commenters stated that to reduce the negative effects on nuclear power, the EPA essentially proposes a nuclear power bailout subsidy to repair the cannibal energy problem it creates with building block 3.146 Commenters stated that building block 4 could also, ironically, increase CO2 emissions. Commenters pointed out that energy expert Robert Michaels has noted that energy efficiency programs can often cause a "rebound effect" that actually raises overall energy use:

" Much of today' s energy policy assumes that regulations mandating greater energy efficiency will reduce energy use. That isn't always the case and energy efficiency improvements are seldom as large as promised by engineering calculations because of "rebounds." For exampl e, people who install lighting that is 50 percent more efficient frequently leave the lights on longer, negating some of the energy savings from greater efficiency. This is called an energy efficiency rebound. Sometimes these mechanisms even bring about ne t increases in energy use known as 'backfires. ' "

Commenters stated that this "rebound effect" is extensively documented by Michaels who notes that "more than 200 studies exist on the subject" and that "most research on direct rebounds...has generally veri fied their existence."

EPA thus not only needs to seriously consider its assumptions for each building block in a vacuum, but also how each block interacts with the others.

Comment 33: BB 1 does not account for the "rebound effect."

Response 33: EPA disa grees

. See response at the beginning of the section for EPA’s response to these comments.

The following are summaries of the specific public comments under this comment:

Commenters stated that it is important to note that EPA's Building Block 1 does not account for what EPA calls the "rebound effect," whereby increased unit efficiency (and any resultant decrease in variable operating costs) might lead the unit to run more because it is more competitive. Commenters stated that this means that the reduction in the unit's CO2 emissions caused by the improvement in its heat rate could be partially offset by the increase in the unit's CO2 emissions associated with increased dispatch. Commenters stated that the extent of the offset would depend on the unit's gen eration after the heat rate improvements, as well as the CO2 emission rates of the units whose generation would be displaced. Commenters contended that the EPA believes that the combination of building block approaches will counteract the rebound effect by encouraging overall reductions in electricity demand and increases in generation from lower

- or zero

- emitting resources.

Comment 34: How the supply of electricity will continue to match demand as renewable and nuclear generation increases and demand d ecreases is not explained.

Response 34: See section final rule Regulatory Impact Analysis for EPA’s assessment of potential impacts of the CPP for EPA’s response to this comment

. See also section VIII for147 pathways that states can choose to implement the fi nal rule requirements for the EPA’s response to this comment.

The following are summaries of the specific public comments under this comment:

Commenters noted that the EPA's building block 3 assumes that renewable energy and nuclear energy generation will increase as compared to the "business

- as

- usual" case, while building block 4 assumptions require electricity demand to be lower than the "business

- as

- usual" case due to demand side energy efficiency measures. However, commenters stated that the EPA fails t o explain how the supply and demand for electricity will continue to balance under those circumstances. As a result, commenters argued that the EPA's assumptions rely on an unrealistic picture of the future, in which there is a greater supply of zero

- emiss ion electricity generation than demand. Commenters stated that the EPA's October 2014 NODA attempts to address this significant discrepancy by proposing to assume that new renewable energy and energy efficiency measures will offset fossil fuel generation, either on a proportional basis (displacing fossil generation in proportion to 2012 generation levels) or a priority basis (displacing higher CO2 emitting resources first). Commenters stated that either proposal will significantly increase the stringency of the proposed goals. Commenters noted that the EPA suggests that this increased stringency might be more representative of the "best system of emission reduction," and indicates that other aspects of its NODA that could offset any increase in stringency, s uch as the proposal to increase the flexibility associated with the interim goals. However, commenters expressed concern that, given EPA's aggressive building block assumptions, the proposed Clean Power Plan is already too stringent. Commenters stated that increasing the level of stringency even further risks placing an even more significant burden on the economy than the originally proposed goals and increases the risk to reliability of the nation's electric power supply. As such, commenters opposed the EP A's decision to require new renewable energy and energy efficiency to offset fossil generation in the goal calculations underlying its proposed Section 111(d) program unless many of its other assumptions are also adjusted to ensure the goals are set at an appropriate level of stringency in each state.

Comment 35: Avoid further rule revisions that would allow a state to use EE gains to increase heat rate or re

- dispatch goals.

Response 35: EPA has revised the goal setting methodology

. S ee section V and VIII of the final rule preamble of the CPP

. The following are summaries of the specific public comments under this comment:

Commenters strongly urged the EPA to avoid any further revision to the proposed rule that would take a state's EE gains claimed under Bl ock 4 and use them to increase either the heat rate (Block 1) or re

- dispatch (Block 2) emission reduction goals already established for fossil plants under the original formula. Commenters stated that it is preferable that any EE additions to the portfolio replace fossil generation only as fossil plants are converted to other fuels or retired at the end of their natural usefulness. Commenters asserted that if states were to redraw the energy generation baseline, and thereby its carbon emissions targets, as a function of EE gains, EGU148 owners would face perennial uncertainty in establishing clear investment and rate setting strategies.

Comment 36: Commenters discussed conflicts among the four building blocks in South Dakota

. Response 36: EPA disagrees with c ommenters suggesting that the building blocks do not work effectively together

. See response at the beginning of the section for EPA’s response to these
comments

. The following are summaries of the specific public comments under this comment:

Commenters st ated that because wind is so variable, natural gas generators need to be available to ramp up quickly to replace wind generation when the wind stops blowing. Yet, commenters noted that the EPA's "best" system has all NGCC units operating as base load units (70% capacity factor) in substitution for coal generation, making them unavailable to ramp up to the levels necessary to replace wind generation as wind diminishes. Commenters noted for instance, Basin Electric Power Cooperative designed the Deer Creek NG CC generating station in South Dakota, which became operational in 2012, to run 12

- 16 hours per day, five days a week. Commenters noted that this equates to a 50% capacity factor rather than the 70% capacity factor that EPA believes would be a component of South Dakota's "best system." Commenters stated that Basin designed Deer Creek to operate in this fashion in order to integrate Basin's abundant and growing wind resources. Operated at a 70% capacity factor, however, commenters noted that Deer Creek would not be able to achieve its design function and, counterproductively from EPA's (and Basin's) perspective, Basin would be required to curtail wind generation

. Commenters stated that the EPA's "best system" for South Dakota founders on this reality.

Commen ters noted that because generation resources do not substitute for each other, building blocks 2, 3 and 4 also work at cross purposes with building block 1. Commenters stated that because coal units are designed to operate as base load plants, they become less efficient and hence produce more CO2 per MWh, if they are forced to cycle; but, for instance, EPA's "best" system for South Dakota would force the "Big Stone" plant to operate at a 23% capacity factor, which is not only inefficient but below its minim um run level of 40%.

Commenters stated that aside from incorrectly assuming an unachievable 6% HRI for South Dakota's singular coal

- fired plant, the EPA ignores the interrelationship between HRI and the other Building Blocks EPA proposed. Commenters state d that implementing Building Block 2 in South Dakota necessarily requires reducing coal

- fired generation in the state. Commenters noted that Building Block 2 reductions could be achieved only by running Big Stone Plant at significantly less than its full c apacity. Even if this were possible, commenters stated that the reduced capacity factor would have a deleterious effect on heat rate as reflected in the GHG Abatement Measures TSD document

. Commenters included a graph of a typical monthly net plant heat ra te chart at Big Stone Plant that the commenters asserted plainly illustrates the heat rate impact of operating at less than full load. Commenters stated a 50% reduction in normal generation loading results in approximately an 8% degradation in heat rate

. F ar from affording states flexibility in achieving overall emissions reductions, commenters asserted that the149 proposed rule's Building Blocks interfere with one another, so that meeting the target in one block (e.g., the re

- dispatch target in Building Block 2) makes it impossible to meet the target in another (e.g., the heat rate improvement target in Building Block 1).

Commenters also stated that building blocks 2 and 3 are in direct conflict of each other. Commenters stated that BB1 expects utilities to i mprove coal

- fired EGUs' heat rates while BB2 expects coal

- fired EGUs to reduce their capacity factors through re

- dispatch. Commenters stated that should EPA's rules require coal

- fired EGUs to reduce capacity factors under BB2, then EPA cannot reasonably ex pect coal

- fired EGUs to improve heat rates by 6 percent. Commenters stated that this is particularly relevant in South Dakota due to the fact that BSP would need to reduce its capacity factor to 23 percent as a result of Building Block 2. Commenters stated that existing natural gas EGUs are currently used for the integration of variable renewable energy generators. Commenters stated that (under the proposal) existing natural gas EGUs would become base load generation, and new natural gas units would need to be built to continue the integration of variable renewable energy generators. Commenters stated that twice the amount of natural gas generation would need to be added to the bulk electric system for EPA's proposed BSER. Commenters stated that this would a dd more costs to South Dakota's consumers.

Comment 37: Commenters stated that the EPA's determination that NGCCs can be utilized at 70% falls far short of the Sierra Club standard that such a BSER be "feasible" and "produce the improved performance neces sary to meet the standard."

Response 37: See sections V.C. and V.D of the final rule preamble of the CPP for the EPA’s response to this comment.

The following are summaries of the specific public comments under this comment:

Citing "historical data," the commenters noted that the EPA determines that a "substantial number of existing NGCC units have proven the ability to sustain 70% utilization rates for extended periods of time." Commenters stated that the Agency, however, makes no mention of how the natio nal average can be ramped up from the 2012 average of 46% to 70% when many such facilities are not designed nor permitted to operate at such a high level and, indeed, only 10% were actually doing so during the 2012 period, a period of unprecedentedly low n atural gas prices. Commenters noted that many NGCCs are located in densely populated residential areas and are only permitted to operate at such a high level during periods of peak demand. Commenters stated requiring states to meet a goal premised on these entities overcoming permitting restrictions based on public safety and reliability concerns is not "reasonably reliable" or "reasonably efficient." Commenters stated that NGCC units are used as a backstop for intermittent generation from renewables and ar e more likely to be subject to bilateral capacity contracts. Commenters stated in a state such as Illinois, where the 2012 utilization rate was 26%, such a dramatic increase cannot be demonstrated due to the physical, technical and environmental constraint s limiting dispatch

. Thus, commenters stated that Building Block 2 will not "produce the improved performance necessary to achieve the goal.'' Commenters stated in Illinois there are only two large NGCC plants currently in operation, and the other large NG CC plant is currently under construction. Commenters stated that one of the smaller NGCC units is a150 retro

- fitted coal

- fired unit with old boilers. Commenters stated that without appropriate verification of operating permit limitations, water supply, fuel s upply and transmission availability, it is irresponsible of EPA to simply "plug'' in a number and believe that operation at this capacity is feasible for any of those units.

Commenters stated that the EPA incorrectly presumes that coal

- fired EGUs and NGCC units may swap dispatch order with little impact. Commenters stated that cycling a coal

- fired unit that was built to be a base load plant significantly decreases its overall boiler and air pollution control equipment efficiency. Commenters stated that com mencing operation of air pollution control equipment is frequently dependent on a unit reaching certain temperatures and/or operational levels. Commenters stated that frequent starts and load fluctuations of a coal

- fired BGU will increase the emissions of air pollutants, including CO2, since a boiler does not operate as efficiently when initially starting up, shutting down, or during load fluctuations. Commenters added that in addition, frequent starts of a unit degrade the equipment unnecessarily, further decreasing the operational efficiency and, thereby, increasing a unit's heat rate. Commenters stated that EPA acknowledges the impact of lower operating loads on the heat rate of coal

- fired units

. Commenters stated the International Energy Agency estimates a supercritical unit expected to operate at a 90% capacity factor increases its heat rate by 2% when operated at a 70% capacity factor. Commenters stated that they have seen heat rate increases of 3

- 5% during months in which it has multiple starts. Commen ters stated because of the close relationship between an EGU's fuel consumption and its CO2 emissions, a heat rate increase would increase CO2 emissions at a one

- to

- one ratio according to EPA's own presumptions

. Commenters stated that the EPA cannot ignore the fact that the CO2 emission rate will actually increase for coal

- fired units that are forced to operate at lower operating loads, transient loads, or with frequent shutdowns and startups. Commenters stated this seems counter

- intuitive and at odds with the expectations of Section 111(d).

Commenters stated that Building Blocks 2 and 3 will contribute in a measurable and significant way toward adversely affecting the national energy efficiency of coal plants in a way that directly conflicts with EPA's exp ectations that the CPP will increase plant efficiency. Commenters noted that the EPA proposes under Building Block 2 to reorder the dispatch of coal and gas plants such that gas plants dispatch before coal plants. Commenters stated that the impact of this decision is to establish NGCC plants as base load power generators and to increase the cycling of coal plants as daily load fluctuates, but neither coal nor gas plants were designed for EPA's new paradigm. Commenters stated that their power is delivered to multiple end users in multiple states, and to the extent that the Illinois EPA seeks to curtail their operations through dispatch it will necessarily be impeding interstate commerce, an act beyond its authority.

Commenters explained that coal plants and t heir associated pollution control systems operate most efficiently when base

- loaded. Commenters stated because it takes a coal

- fired boiler long periods of time to transition from a cold start to efficient operating temperatures, most load following units will reduce to minimum load rather than shut down when demand is low. Commenters stated that this is a highly inefficient operating mode for such plants. Furthermore, commenters stated that changing load (increasing or decreasing) on a coal fired boiler in volves the starting and stopping of fans, coal pulverizers and associated equipment, and there is concomitant delay in achieving stable, operations following a load change. In addition, commenters noted that some pollution control equipment (SCR, ESP, etc. ) cannot be operated151 until specific operational temperatures are reached. Therefore, commenters noted that operating a coal plant in load following mode increases emissions of criteria air pollutants as well as CO2, and could result in the plant exceeding permitted limits. Since commenters were permitted and financed as a base load operation, strict permit limits were accepted in order to allow construction of the plant.

Commenters noted that the EPA concedes that starting up unit and operating a unit in a transient state (rather than allowing continuous steady state) erodes unit efficiency. Yet, The commenters noted that the EPA is proposing to operate existing coal

- fired plants in the most inefficient manner possible by setting state goals that cannot be m et without requiring EGU's to de

- rate or shutdown and startup frequently. Commenters argued that this is antithetical to EPA's stated goal of improving energy efficiency.

Unlike coal plants, commenters stated that NGCC units can be brought on line relatively quickly with limited loss in efficiency and can match load requirements more quickly due to the more tolerant operating parameters. Commenters noted that under EPA's new dispatch model, plants designed to follow load will now be run constantly a nd plants that were designed to run constantly will follow load. Commenters stated an operational shift such as this will negatively impact coal plants' efficiency and environmental profile.

Commenters stated that while it appears that the most efficient c oal plants in the nation will still generally be required to operate as base load units, most of the coal generation fleet that operates as base load today will transition to peaking or intermediate level dispatch by 2020. Commenters stated that increased cycling of coal plants will require operation at levels that are sub

- optimal and will reduce the efficiency profile. Additionally, commenters stated that coal units' pollution control systems operate more efficiently at higher loads meaning that the parasi tic load required for operations as a percentage of energy produced will be higher

- further degrading performance.

By promoting the use of NGCC units in a manner that these plants were not intended to be used for, the commenters argued that the EPA is prom oting the use of coal

- fired power plants as load cycling at a lower duty cycle, with much more frequent startups and shutdowns, a highly inefficient method of operation and one that was not intended when the plants were constructed, particularly for PSGC w hich was designed and financed for meeting a 90% or greater capacity factor.

Comment 38: Commenters stated that the EPA's methodology in Building Block 1 is internally inconsistent with the methodologies its uses to establish Building Blocks 3 and 4.

Response 38: EPA disagrees with commenters suggesting that the building blocks are inconsistent

. See response at the beginning of the section for EPA’s response to these comments

. The following are summaries of the specific public comments under this comme nt:

Commenters noted that in Building Block 3, EPA examines renewable portfolio standards in states where they exist and undertakes an average of the standards to establish individual state standards in the region. In the alternative methodology, commenter s noted that the EPA relies on152 an NREL study that examines the renewable energy opportunities that are technically feasible to establish state standards under Building Block 3. Commenters stated that while there are significant problems with both of those methodologies as subsequently discussed, the EPA's unwillingness to utilize a standard that relies on technical achievability for HRI (or an average thereof) is curiously inconsistent. Similarly, commenters stated that the EPA utilizes a methodology in Bui lding Block 4 based on the level of energy efficiency savings that "twelve leading states have either achieved

- or have established requirements that will lead them to achieve

- annual incremental savings rates of at least 1.5 percent." Commenters noted t hat in Building Block 4, states that are already at or nearing 1.5% energy efficiency ("EE") savings are not penalized with a requirement to exceed the high water mark. Commenters stated that inconsistently, for Building Block 1, even the leading states ar e expected to achieve an additional 6% HRI. Commenters asserted that the EPA cannot argue that additional EE savings are unattainable but also argue that HRI improvements are attainable because EPA never analyzed what HRI was technically feasible for EGUs. Commenters stated that the EPA deems it appropriate to establish a standard based on an average of what certain states can technically achieve, but completely abandons the concepts of averaging and technical feasibility in Building Block 1.

Comment 39: C ommenters stated that the EPA's BSER assumptions do not fully account for the challenges of adding additional renewable generation to the system.

Response 39: EPA disagrees

. See Preamble Section V.E and the GHG Mitigation Measures, Chapter 4

.
The followi ng are summaries of the specific public comments under this comment:

Commenters stated that the EPA appropriately included existing renewable resources in its determination of BSER and the calculation of state emission goals. Commenters stated that their

e xperience as a leader in renewable energy development confirms that renewable energy can be a
cost

- effective and meaningful way to achieve compliance with state 111(d) targets. However, commenters stated that the EPA's BSER assumptions do not fully account for the challenges of adding additional renewable generation to the system. Specifically, commenters stated that the amount of renewable resource development as well as energy efficiency program growth under Block 4 assumed by EPA exceeds currently projec ted load growth in many cases. Commenters stated that in order to accommodate the additional energy, states would need to reduce the output from other resources to balance generation and load. Accordingly, commenters stated that Nevada cannot simply "add" zero

- emitting resources to its resource mix to achieve the emissions rate goal; it must also reduce energy from other resources so that resources and demand are balanced. Commenters stated that renewable energy and energy efficiency will not work as stand

- alone compliance options; rather, they must be coupled with additional fossil

- fueled resources to deliver the desired output capacity and ensure grid stability. Therefore, c ommenters stated that a balance of various resources options must be employed to en sure ongoing system reliability. Commenters stated that the EPA did not adequately address system reliability considerations in its application of renewable generation. Commenters stated that many renewable technologies, such as wind and solar plants, prod uce intermittent generation that can153 be difficult to predict. To manage the variability and uncertainty inherent with intermittent renewable resources, commenters stated that system operators must have sufficient resources with operational flexibility held in reserve, known as operating reserves, to quickly respond to fluctuations in intermittent renewable generation. Commenters stated that the renewable energy building block used in the proposed BSER will also require incremental operating reserves to main tain system reliability. Commenters stated a BSER that will reduce operational flexibility by limiting the operating reserve capability of NGCC plants while simultaneously increasing the need for operating reserve capacity needed to manage intermittent ren ewable resources is difficult to justify, and imprudent to implement. Commenters recommended that the EPA should ensure that the final rule can be implemented by the states within the proposed timeframes without compromising reliability of the integrated e lectric power system.

Comment 40: Commenters stated that t h e bu il d i n g b l o c k s mu s t b e ho listic a ll y i n t eg r a t ed

, o r t h e S t a t e s ris k t h e " Ge r m a n p r ob l e m " o f h i g h c o st s c au s e d b y ne w i n v e st m en t c oup l e d w it h h i g h CO 2 e m issi on s fr o m f o ssi l EGU s stil l neede d f or gri d relia b ility

. Response 40: EPA disagrees with commenters suggesting that the building blocks do not work effectively together in an integrated way

. See response at the beginning of the section for EPA’s response to these comments

. The following are s ummaries of the specific public comments under this comment:

Commenters stated that, as de scri bed i n t he Fi nAd vic e r epo rt , Ge r m any's app r oa c h t o

r enewab l es has r e s u lt ed i n h i gher power c o sts , a fi nan ci a ll y weakened power s e ct o r , and ir on ic a ll y no r eal CO2 e m issi ons R edu cti on s

. Commenters stated that, as illustr a t ed i n t he CA IS O ' Du c k Cu rv e ', provided by the commenter s , st eep ra mp i ng needs a nd o v er g ene r a ti on risk w il l r equ ir e fl e xi b l e gene rati on. Commenters stated that the s e ope r a ti onal and i n t e gr a ti on

c on str a i n t s put t he t h ir d Bu il d i ng B l o c k i n c on flic t w it h t he firs t t wo.

Commenters noted:

• F irst

, t h e Bu il d i n g B l o c k 1 Hea t Ra t e i m p r o v e m en t s depen d o n t h e ope r a ti on a l

env ir onment

. I n cr ea si n g Renewab l e Gene r a ti o n w il l c au s e cycli ng , pa rt

- l oa d
ope r a ti on , an d m o r e fr equen t start up s a n d s hu t down s t h a t w il l deg r ad e H e a t Ra t e i m p r o v e m en ts

.

• Se c ond

, t h e ab ilit y t o a c h i ev e t h e Bu il d i n g B l o c k 2 D is pa tc h i n cr ea s e s a t o l de r Na t u r a l Ga s Comb i ne d C ycl e P l an t s w il l b e i mp air e d i f Du c k Cu rv e o v e r

ge n erati o n ris k b ec om e s w i d es p rea d

. The s e p l an t s wou l d a ls o b e s ub j e c t t o cycli n g an d pa rt

- l oa d ope r a ti o n t ha t w il l i m pa i r Hea t Ra t e s

.

• Th ir d

, greate r R e n e w a b l e G e n erati o n ( Bu il d i n g B l o c k 3 ) w il l ne c e ssit a t e d is p atc h a b l e powe r fr om gas

- fir e d pea ki n g p l an t s o r ene r g y st o r a g e t o m a i n t a i n gri d r e li ab ility

. H ig h H e a t Ra t e pea ki n g p l an t s a r e e x pen siv e t o op er a t e an d154 w il l o ffs e t t h e e m issi on s r edu cti on s o f t h e Renewab l e ge n erati on , a n d

ex p e n siv e b atterie s wi l l d riv e u p ene rg y c o st s an d i m pa i r ec ono m i c g r ow t h.

Commenters suggested that ra t her t h a n vi ew i ng r enewab l es and c on v en ti on a l f uel s ou rc es i n oppo siti on, t hey c an be sy ne r g istic a ll y h y b ri d iz ed t o e c onom ic a ll y a c h i e v e l a r ge r edu cti ons of CO2 e m issi ons at l ower c o st . Commenters stated that the s e bene fit s a ris e be c au s e t he e ffici ent h y b ri d syst e m s en a b l e g r ea t er r enewab l e gene r a ti on w it h f ar l e s s f uel c on s ump ti on t h a n

c onven ti on a l pe a k i ng p la n t s u s ed t o ove rc ome i n t e r m itt en c y. Commenters noted that the bene fit s of h y b ri d iz a ti on a r e ill u str a t ed by h y b ri d au t o m ob il e s , wh ic h demon str a t e t he sy ne r gy of m e c han ic al and e l e ctric al p r opu lsi on syst e m s.
Likewise in the electric power industry, commenters stated that integration of thermal

- based renewable generation and energy storage technologies with fossil

- fired thermal EGUs deliver cost, efficiency and emissions synergies. Accordingly, commenters recommended that the Clean Power Plan include:

• Consideration of expected performance of coal and gas

- fired EGUs (building blocks 1 and 2) in the operational context along with renewable generation resources (building block 3).

• Consideration of energy storage as a fifth building block to support renewable generation without impairing Heat Rate or Capacity Factor of fossil EGUs

• Consideration of hybrid fossil

- renewable generation and storage systems a s an element of the three building blocks:

• Solar thermal hybridization to reduce Heat Rate of fossil EGUs.

• Fossil

- assisted energy storage to increase Capacity Factor and improve Heat Rate at coal and gas EGUs to ameliorate renewable intermittency, over

- generation risk, and ramp risk.

• Integration of solar thermal and energy storage at new

- build EGUs in the U.S. Southwest to provide renewable capacity when needed, with superior Heat Rates at market prices.

Commenter s stated that i n cl ud i n g t he se c on si de r a ti on s in t h e CP P w ill enab le t h e St a t e s an d
t h e Un it e d St a t e s to a c h i e ve r edu cti o n o f CO 2 e m issi on s m o re qu ickly an d m o re c o st

effectively.

Comment 41: BSER should include a requirement to evaluate and address integration and reliability issues

Response 41: EPA disagrees

. The building blocks are designed to work in an integrated manner

. See response at the beginning of the section for EPA’s response to these comments See section VIII.G of the final rule preamble of the CPP for reliability considerations.155 The following are summaries of the specific public comments under this comment:

Comm enters stated that the proposed BSER has great potential to reduce greenhouse gas emissions. Commenters said, absent a specific BSER requirement to evaluate and address integration and reliability issues, however, the BSER could inadvertently fail to achie ve its objectives. Commenters said, a balanced portfolio that incorporates renewable resources capable of providing the ancillary services needed for grid reliability is essential to avoiding erosion of emission reduction gains expected from improvements t o EGU efficiency (Building Block 1), as well as to gaining the most value from, and avoiding waste in, clean energy resource procurement (Building Block 3).

Commenters stated, it appears that EPA made numerous assumptions in the proposed guidelines about t he emission reductions achievable by each separate Building Block that are unsupported by evidence in the record. Commenters said, while it is EPA's role to determine BSER in compliance with the provisions of the CAA, ultimately it is the role of the state s to determine the application of the BSER to specific affected units within that state. Commenters said, EPA has a statutory obligation to ensure that BSER is adequately demonstrated and to show that the state emission rate goals are achievable, particula rly in light of the interconnected nature of the power system. Commenters said, EPA's assumptions and conclusions about the individual Building Blocks that EPA identified in setting BSER should be scrutinized in light of the best available data and experie nce and, adjusted as necessary. Commenters said, EPA should ensure that the state emission rate goals in the final rule reflect an evaluation of all BSER components together in order to properly reflect the interconnected nature of the power sector and app ropriate assumptions and conclusions about the level of reductions achievable by each component.

Comment 42: Electricity sources do not substitute for each other.

Response 42: EPA disagrees

. The building blocks are designed to work in an integrated manne r as alternatives, not to act as perfect substitutes

. See response at the beginning of the section for EPA’s response to these comments See section VIII.G of the final rule preamble of the CPP for reliability considerations . See also final rule Regulatory Impact Analysis for the potential power sector impacts of the rule.

The following are summaries of the specific public comments under this comment:

Commenters stated that EPA bases its proposal on the supposition that utilities "treat increments of generat ion as interchangeable between and among sources in a way that creates options for relying on varying utilization levels, lowering carbon generation, and reducing demand as components of the overall method for reducing CO2 emissions." Commenters said as a result, EPA designs its state "best systems" and calculates the state goals as if increasing natural gas generation can automatically displace coal power, and increasing nuclear and renewable power can automatically displace coal and natural gas power.

C ommenters said this premise is demonstrably false; grid operations are considerably more complicated. Commenters said that coal and nuclear units operate best when operated as base load units because they cannot cycle up and down quickly. Commenters said c oal and nuclear156 units also perform important grid

- stability functions that other resources cannot perform, as discussed further below. Commenters said although NGCC units can operate in base load mode, they have traditionally operated as intermediate units , cycling to follow load because they can ramp up and down quickly. Commenters said that simple cycle natural gas units typically run as peaking units. Commenters said wind and solar units operate intermittently as the wind blows and the sun shines. Commen ters said that these resources must be backed up with natural gas units to ensure that the grid remains in balance as wind and solar power fluctuate.

Commenters stated that one of the great fallacies of the rule is that it would reverse the traditional fun ctions of NGCC and coal units. Commenters said that, despite their ability to cycle up and down quickly, natural gas units would increasingly be relied on to serve a baseload function. Commenters said despite the inability of coal units to cycle up and dow n quickly, coal units would be forced to cease operating as baseload units and would instead be called on to operate intermittently. Commenters cited the Electric Power Research Institute (EPRI) expressing "concern that today's coal fleet may not be able t o provide adequate flexible operations capabilities for the overall fleet as most existing coal plants were not originally designed for such duty." Commenters cited that NERC made the same point:

"Grid reliability issues associated with increased variable resources are not directly addressed in the EPA's proposed Building Blocks. Conventional generation (e.g., steam and hydro), with large rotating mass, has inherent operating characteristics, or ERSs, needed to reliably operate the BPS. These services inclu de providing frequency and voltage support, operating reserves, ramping capability, and disturbance performance. Conventional generators are able to respond automatically to frequency changes and historically have provided most of the power system's essent ial support services. As variable resources increase, system planners must ensure the future generation and transmission system can maintain essential services that are needed for reliability.

A large penetration of VERs will also require maintaining a suf ficient amount of reactive support and ramping capability. More frequent ramping needed to provide this capability could increase cycling on conventional generation. This could contribute to increased maintenance hours or higher forced outage rates, potent ially increasing operating reserve requirements. While storage technologies may help support ramping needs, successful large

- scale storage solutions have not yet been commercialized. Nevertheless, storage technologies support the reliability challenges tha t may be experienced when there is a large penetration of VERs, and their development should be expedited."

Commenters stated that wind units pose particular challenges for the grid because the wind tends to blow less when the weather is the hottest or the coldest and therefore when electric demand is the highest. Commenters said the availability of wind can fall quickly. Commenters said that, for instance, on one day in Texas, wind generation dropped by 93% (a total loss of 6,500 MW) over 13.5 hours. Comme nters said that on another day, wind generation dropped by 3,430 MW in 10.8 hours. Commenters said as a result, although wind resources can have annual capacity factors of 40 percent or even more in some areas, these resources are assigned much smaller cap acity157 factors in determining their contribution to generation reserves available to meet system peaks. Commenters said that, MISO, for example, assigns wind a system

- wide capacity credit of only 14.1%. Commenters said fossil and nuclear resources, in contr ast, can be counted on to operate reliably year round.

Comment 43: Electricity Sources do not Substitute for Each Other

Response 43: EPA disagrees

. The building blocks are designed to work in an integrated manner as alternatives, not to act as perfect sub stitutes

. See response at the beginning of the section for EPA’s response to these comments See section VIII.G of the final rule preamble of the CPP for reliability considerations. See also final rule Regulatory Impact Analysis for the potential power
sect or impacts of the rule

. The following are summaries of the specific public comments under this comment:

Commenters stated that the Proposed Rule is based on the supposition that electric utilities "treat increments of generation as interchangeable between and among sources in a way that creates options for relying on varying utilization levels, lowering carbon generation, and reducing demand as components of the overall method for reducing CO2 emissions." Commenters said that as a result, EPA designs its st ate "best systems" and calculates the state goals as if increasing natural gas generation can automatically displace coal power, and increasing nuclear and renewable power can automatically displace coal and natural gas power.

Commenters stated that EPA's premise is false; power generation and electric grid operations are considerably more complicated. Commenters said that coal and nuclear units operate best when operated as base load units because they cannot cycle up and down quickly. Commenters said

coa l and nuclear units also perform important grid

- stability functions that other resources cannot perform. Commenters said although NGCC units can operate in base load mode, they have traditionally operated as intermediate units, cycling to follow load becau se they can ramp up and down quickly. Commenters said that single cycle natural gas units typically run as peaking units. Commenters said wind and solar units operate intermittently as the wind blows and the sun shines. Commenters said that these resources must be backed up with natural gas units to ensure that the grid remains in balance as wind and solar power fluctuate. Commenters said that, in sum, different generation resources do not substitute for each other. Commenters said the Proposed Rule is thus flawed at this most fundamental level.

Commenters said because generation resources do not substitute for each other, building blocks two, three and four also work at cross purposes with building block one. Commenters said because coal

- fueled EGUs are des igned to operate as base load plants, they become less efficient

- and hence produce more CO2 per MWh, if they are forced to cycle.158 3.7 FUEL SWITCHING

This section addresses comments which relate primarily to the possible use of natural gas or biomass as a fuel, either in combination with coal or instead of coal, as a means of reducing CO 2 emissions. The EPA has responded to many of these comments in the preamble to this CPP final rule, or in related TSDs. Thus, where appropriate, this section also makes ref erence to the relevant preamble section or TSD for such responses.

3.7.1 Coal

- to

- natural gas

This subsection addresses comments on the use of natural gas in coal

- fired EGUs as a potential means of reducing CO2 emissions. In this subsection the EPA’s use of the terms co

- firing and fuel switching refer to coal

- fired EGUs that either co

- fire a significant amount of natural gas with coal, or convert to the use of natural gas in part or totally as the boiler fuel.

As part of the EPA’s response to all comments in this subsection, please see preamble section V.A.6.a of the CPP Final Rule for the non

- BSER measures that reduce CO2 emissions per MWh generated. Please also see chapter 6, Fuel Switching, in the GHG Abatement Measures TSD of the proposal, for the EPA’s detailed analysis and conclusions regarding coal

- to

- gas conversions. In our review of the comments received on coal

- to

- gas conversion

, we found no commenters’ input/analysis that would compel a substantive revision of our proposal TSD. We

, therefore

, consider the proposal TSD to be applicable in response to all comments on coal

- to gas conversions

. Overarching comments and the EPA responses are presented below.

Comment 1 : Some commenters stated that it is important that fuel switching not be mandato ry, but that it can be used as an option to obtain CO 2 and other pollutant reductions.

Response 1: The EPA agrees that coal

- to

- gas fuel switching in existing coal

- fired EGUs is an important CO 2 reduction option, and that it would have additional pollutant reduction benefits. Fuel switching is not mandatory under this CPP final rule.

The following are summaries of the specific public comments under this comment:

Commenters stated they are in favor of natural gas co

- firing or conversion to be part of BSER as it is an option for those plants that are considering or have implemented such conversions. Commenters stated that it is important that it is not mandatory, bu t can represent a significant reduction in carbon and NOx emissions as cited in the examples set forth in the EPA proposal. Commenters stated that the EPA could provide an information packet on the benefits of co

- firing to coal

- firing plants and subsequent follow

- up to see if plants would consider or are implementing such conversions. Commenters stated that with such data, EPA can estimate the159 benefit (e.g. achieving goals sooner or exceeding the goals within stated timelines) of including or not including such an approach for BSER.

Commenters supported gas conversion and co

- firing opportunities as compliance options. However, commenters stated that they encourage the EPA to collaborate with the Economic Development Administration, Department of Energy, and Department of Commerce to allow natural gas pipeline projects and to provide financing programs.

Commenters stated that determination of BSER in the final rule should not include mandatory conversion to or co

- firing of natural gas (because it may not be te chnically or economically feasible for all affected EGUs), but that voluntary fuel switching or co

- firing should be allowed for the compliance demonstration..

Commenters stated, EPA states that it "does not propose to consider [natural gas conversion or

c o

- firing at coal

- fired utility boilers] part of the best system of emission reduction adequately demonstrated for existing EGUs." 79 Fed. Reg. at 34,875. Commenters said, this conclusion is due largely to the high costs of implementing such a conversion. C ommenters said, however, EPA "solicit[s] comment on whether natural gas co

- firing or conversion should be part of the BSER." Id. at 34,876. Commenters agreed that natural gas conversion and co

- firing are not BSER for coal

- fired EGUs and should not be incl uded in the Proposed Guidelines. Commenters said, although sources should have the option to voluntarily use these measures to comply with CO2 emission standards, natural gas conversion and co

- firing are extremely costly and are appropriate only for certai n EGUs based on site

- specific factors. See Lowell L. Smith, "Overview of Natural Gas Conversion Options To Meet Emission Requirements on Coal

- Fired Electric Generating Units" (Nov. 2014) ("Smith Report").

Commenters stated, clearly, EPA is overreaching its authority in even suggesting that it can establish a minimum amount of natural gas to be burned in each state. Commenters said, EPA simply does not possess that authority. Commenters said, while it may be appropriate to allow a source to determine whether it is cost effective to co

- fire natural gas, it is a compliance option that should remain up to the source. Commenters said, EPA can neither mandate nor preclude the use of fuel

- switching or co

- firing of natural gas as a means of compliance with a perform ance standard. Commenters said, it is not within EPA's authority to mandate the use of natural gas, through the required construction of new NGCC units, fuel switching or co

- firing in the emissions guidelines, nor is it within the authority of state air po llution control agencies to include these requirements in setting a performance standard.

Comment 2: Commenters provided various reasons for recommending that fuel switching not be part of the BSER, including the argument that over the long run natural g as can be more efficiently and more economically used, and with much less CO2 emission per MWh, in existing underutilized NGCC units or in new NGCC units.

Response 2: We acknowledge these comments that are supportive of the EPA analysis and conclusions.

T he following are summaries of the specific public comments under this comment:160 Commenters stated that fuel switching and co

- firing should not be included in the BSER because NGCCs are 46% more efficient. Commenters stated that the US should be investing in carbon free EGUs, even if there are stranded costs.

Commenters stated that what is needed to increase efficiency is for coal

- fired plants to switch to natural gas or to build nuclear power plants.

Commenters stated that EPA should exclude gas co

- firing, a nd conversion of coal

- fired EGUs from BSER. Commenters stated that the conditions under which gas conversion or co

- firing would be considered a potentially economic option are site

- specific and highly dependent on upon, among other things, the proximity of a coal

- fired plant to gas supply and boiler configuration.

Commenters stated that another option for reducing CO2 emissions is switching to a fuel which emits less CO2. Commenters said, historically, EPA has not considered redefining the design of

a sourc e when considering available control options. Commenters said, therefore, fuel switching generally cannot be considered an available control option.

Comment 3: Some commenters provided detailed discussion of the many technical factors and performance effe cts to be considered with fuel switching. They generally conclude that fuel switching may be economically viable for certain limited purposes such as peaking duty and grid reliability, or for relatively short time frames such as for avoiding costlier modif ications for MATS compliance, or in other particularly favorable site specific circumstances. They also generally conclude that because natural gas prices are projected to increase over longer time frames, fuel switching will be uneconomic for the long run in most cases when compared to using natural gas in NGCC units.

Response 3: The EPA acknowledges these comments supportive of our fuel switching analysis and conclusions. We have also noted that our analytical assumptions regarding capital and O&M
costs , and performance effects for fuel switching are for the most part in agreement with the assumptions used in commenters’ own analyses.

The following are summaries of the specific public comments under this comment:

Commenter s stated that EPA's premise that a significant portion of the CO2 reductions the proposed rule seeks to achieve can be done through fuel switching from coal to natural gas is based on questionable assumptions regarding natural gas supply, price, and infrastructure avail ability. Commenters stated that t he Proposed Rule states that it would reduce nationwide CO2 emissions from the power sector by approximately 30 percent from 2005 levels by 2030. Commenters believe d that the rule indicates a significant portion of this reduction would be achieved through fuel switching from coal to natural gas. Commenters stated that that the large amount of coal generation in existence today is a direct result of action by the federal government.

Commenters stated that p assage of the Powerplant and Industrial Fuel Use Act in 1978 by Congress restricted the construction of natural gas

- fueled power plants and that e lectric utilities161 were not allowed to construct new natural gas plants until passage of the Natur al Gas Utilization Act of 1987, which repealed the provisions of the Powerplant and Industrial Fuel Use Act. Commenters stated that f ederal policies such as these and others promoted coal as a fuel source for electric generation. Commenters stated that by 1987, 56.9 percent of all electric generation was from coal. Commenters stated that this episode foisted on consumers and the electric power industry was the product of natural gas supply forecasts by the natural gas industry and the federal government.

Co mmenters stated that the EPA assumes relative ease to the power sector and low cost to consumers in essentially requiring a massive switch from coal to gas. Commenters stated that
t his assumption by EPA is problematic given it fails to take into account a host of issues that are very likely to impact the supply and price of natural gas, as well as impediments to the expansion of natural gas infrastructure needed to facilitate fuel switching. Commenters stated that the agency assumes relatively flat long

- ter m natural gas prices and ample supply, but does not take into account how increased demand for natural gas by domestic manufacturers, the transportation sector, and international markets is likely to reduce supply and increase prices. Commenters stated tha t t he agency also assumes that natural gas infrastructure can be expanded to meet the significant increased demand of electric utilities in a relatively short amount of time. Commenters stated that EPA needs to reexamine these assumptions and adjust its ti metables for reducing CO2 emissions from fuel switching.

Commenters stated that EPA's approach in setting targets based on a state's ability to switch fuel is "akin to the IRS taxing people based on the size of their savings account, regardless of income". Commenters stated that although they have some natural gas infrastructure, natural gas has not been competitive in the state relative to coal and therefore it would be inefficient to run the plants at higher capacity factors.

Commenters supported moving from coal to natural gas, because the higher efficiency levels of gas turbines means that there is less waste heat, and therefore gas uses half or less of the water needed for coal plants.

Commenters stated that fuel switching should not be considered an a cceptable method for achieving heat rate improvements. Commenters stated that while the amount of CO2 would decrease from a unit that switched from natural gas to fuel, this is due to the amount of CO2 released by the fuel and not due to an improvement in heat rates. Commenters also feared that a conversion would trigger NSR.

Commenters provided talking points regarding coal to natural gas conversion. Commenters discussed briefly the impact of natural gas conversion on CO2, NOx, SO2, HCl, CO, particulates, and Hg

. Commenters stated in general that emissions would decrease for these pollutants to the degree which natural gas was used over coal.

Commenters stated that conversion to natural gas would present technical challenges. Commenters did not provide mu ch data, but qualitatively stated that the following technical categories had potential challenges: initial boiler design, burner design, gas piping, burner management, boiler and combustion controls, convective pass, control systems, burners, emissions c ontrol systems, pipeline proximity, pipeline capacity, natural gas residential to162 industrial breakdown, long term natural gas supply, natural gas interruptions, and costs/benefits of alternative emission reduction methods.

Commenters provided more detail o n convective pass, control systems, burners, and emissions control systems.

Commenters stated that it is likely that converting a coal

- fired boiler to burn appreciable amounts of natural gas will be costly. Commenters stated EPRI has estimated that fuel sw itching, CO2 capture and disposal, and new generation capacity are potentially the three most costly CO2 emission reduction methods.

Commenters stated that conversion from coal firing to natural gas firing to meet regulatory requirements can be an economic ally feasible option given the right circumstances. Commenters stated that there appear to be no major technical obstacles to converting a coal

- fired boiler to fire 100 percent natural gas. Commenters stated that the two primary obstacles to making this na tural gas conversion economically feasible are the availability of a natural gas supply and the new pipeline costs that may be required to bring the gas to the plant. Commenters stated that other factors that cloud the understanding of the exact costs to c onvert to natural gas are the potential natural gas price escalation and the cost to convert the EGU to burn natural gas. Commenters stated that both of these factors are not well defined at this point in time.

Commenters summarized various boiler design considerations for EPA to review when converting from coal to natural gas. Commenters stated that the information provided on design considerations is summarized from the report "Guidelines for Conversion from Coal and Oil to Gas Firing" which was issued by EPRI in 1995; the report was prepared by Stone & Webster and is a detailed evaluation of the changes necessary to convert a coal only boiler to fire 100 percent natural gas

. Commenters provided mostly qualitative discussions of the following:

Convective Pass Design

- Commenters discussed the issue of convective pass and concluded that there should not be any major issues, but that a detailed modeling effort would be needed to determine the necessity for major convective pass changes to individual boiler designs. Commenters stated that incorporation of a flue gas bypass around the convective section would also be a potential method of controlling critical convective pass temperatures increases if the ability to fire both fuels were to be maintained.

Combus tion Air Supply Design

- Commenters discussed the issue of excess air and stated that for most coal

- fired boilers, the forced draft fan capacity would likely be sufficient to supply the required air to reach the boilers maximum continuous rating firing onl y natural gas.

Commenters discussed changes to control systems when firing natural gas and/or coal. Commenters stated that if the natural gas and coal are fired separately, control systems for the two fuels may be relatively independent and consequently le ss complex. Commenters stated that if natural gas and coal are fired simultaneously, the control system becomes more complex and more costly. Commenters stated that conversions to fire either natural gas or coal in certain parts of the country would likely depend upon the potential for interruptible gas supplies. Commenters stated that due to the potential seasonal unavailability of natural gas in some regions of the country (many in the Northeastern region), it is likely that seasonal firing of the two fu els would163 be the preferable alternative. Commenters stated that this would allow tailoring the natural gas generation based upon its seasonal availability, potentially minimize the conversion costs and provide a fail

- safe method to respond to fuel availabi lity swings.

Commenters stated that burner designs to accommodate simultaneous firing of natural gas and coal have been available for many years. Commenters stated that the specific design of these dual fuel burners depends upon the existing burner design and the boiler type (wall

- or tangential

- fired). Commenters stated that retractable gas canes can be retrofit to the existing coal fired burners. Commenters stated that this might be accompanied with alterations to the secondary airflow vanes or registers. Commenters stated that in some cases a completely new burner may be required at a significantly higher cost. Commenters stated that the condition of the existing burners and the method of firing the natural gas and the ability to control the airflow would determine whether retrofit with new burners was appropriate on a case

- by

- case basis.

Commenters stated that many of today's large coal

- fired boilers can have a full complement of emission control equipment including particulate, SO2 and NOx removal equipm ent. Commenters stated that depending upon the method of firing natural gas with coal, the method of use of these control devices may need to be significantly altered if natural gas conversions are considered. Commenters stated that approximately 40 percen t of the coal

- fired boiler population does not have one or both of these advanced emission control systems. Commenters stated that these EGUs may be good candidates for considering natural gas conversion in place of installing the advanced control systems.

Commenters stated that if the method of firing natural gas was to fire either fuel but not both simultaneously, considerable operational savings could accrue. Commenters stated that when firing natural gas the particulate and SO2 equipment would likely n ot need to be operated. Commenters stated that on the other hand, the existing NOx control equipment, such as SCR, would likely need to be operated to continue to reduce NOx. Commenters stated that due to the decreased NOx emissions on natural gas, the amm onia supply and control systems would likely require some alterations. Commenters stated that typically, firing natural gas in a coal

- fired boiler decreases the thermal efficiency by as much as 5 to 7 percent due to the latent heat losses and moisture form ation. Commenters stated that some of this potential loss can be compensated for by the decreased use of the auxiliary equipment associated with coal firing

-- coal mills, coal yard equipment, and emission control equipment. Commenters stated that the degr ee of this compensation would have to be evaluated on a case

- by

- case basis.

Commenters stated that if the method of firing natural gas was to simultaneously fire both fuels, the potential efficiency credits associated with reduced auxiliary equipment opera tion would not be available. Commenters stated that in this case the thermal efficiency loss associated with operation on combined firing of natural gas and coal would be dependent on the amount of natural gas fired (usually less than 20 percent). Commente rs stated that in all cases it would be much less than that for coal only firing.

Commenters stated that the degree to which alteration to fire both natural gas and coal in a coal

designed boiler will be dependent on the basic design of the boiler and the current deficiencies of the boiler with regard to its operating at design conditions. Commenters stated that based on these current boiler operating conditions, converting to fire natural gas may require changes to164 some or all of the components mentioned a bove. Commenters stated that since the boiler may never have had the capability to fire significant amounts of natural gas, the control systems will nevertheless need to be altered.

Commenters stated that conversion from coal firing to natural gas firing t o meet regulatory requirements can be an economically feasible option given the right circumstances. Commenters stated that there appear to be no major technical obstacles to converting a coal

- fired boiler to fire 100 percent natural gas. Commenters state d that the two primary obstacles to making this natural gas conversion economically feasible are the availability of a natural gas supply and the new pipeline costs that may be required to bring the gas to the plant. Commenters stated other factors that cl oud the understanding of the exact costs to convert to natural gas are the potential natural gas price escalation and the cost to convert the EGU to burn natural gas. Commenters stated that both of these factors are not well defined at this point in time.

Commenters discussed the history of coal boilers and stated firing natural gas in coal

- designed boilers has been accomplished for many years. Commenters provided background data and figures to show that older boilers often had more capacity to fire natura l gas than modern boilers. Commenters provided this data to support the suggestion that implementation of natural gas firing in coal

- fired boilers may involve a wide range of alterations dependent upon the original boiler design and previous upgrades to me et Title IV and other regulatory requirements. Commenters provided the following potential categories of implementation alterations that may be required for coal

- fired boilers to fire significant amounts of natural gas.

• Boilers originally designed to fire both natural gas and coal.

• Retained original firing capabilities,

• Altered boiler/controls or abandoned natural gas firing capabilities.

• Boilers designed to fire only coal as the generating energy source

• Boilers designed to burn small amounts of natural ga s for warm

- up and/or igniters

• Boilers with no natural gas supply.

Commenters discussed qualitatively (e.g., cost are small, costs are significant, cost are prohibitive) at length what the costs would be for these four proposed categories and what some of the hurdles for conversion may be.

Commenters stated that efficiency impacts are due primarily to losses associated with the high hydrogen content in natural gas, and lower combustion temperatures and heat transfer differences result in steam production ca pacity de

- ratings for coal boilers burning natural gas. Commenters stated that it is costly to construct gas pipelines to supply existing coal units that currently do not have sufficient natural gas supply infrastructure in their general area. Commenters s tated that the cost for a lateral gas line currently under construction to supply a new TVA NGCC plant is approximately $4MM per mile, or $80MM for a 20 mile long pipeline. Commenters stated that where mainline expansion or additional compression is requir ed, costs165 are tens of millions of dollars higher. Commenters stated that in addition to pipeline costs, natural gas process piping, new combustion controls and combustion equipment has to be installed inside of the plant boundaries to make the unit capable of co

- firing natural gas.

Commenters stated that fuel switching is not consistent with the definition of the affected source

. Commenters noted that co

- firing with gas with coal or coal to gas conversion could increase emissions for some pollutants, prompt ing some form of PSD or NSR review. Commenters stated that even if co

- firing were consistent with the definition of BSER, each unit would be required to implement a case

- by

- case determination, re

- permitting, and PSD/NSR evaluations. Although the EPA is off ering flexibility by giving the option to co

- fire or convert plants, the commenters stated that studies conclude that each boiler would have specific challenges to evaluate and overcome should it be shown that the corresponding modifications to add gas fir ing capability would be viable.

Commenters had received permission to convert two coal

- burning units into natural gas units. Commenters stated that the efficiency of converted units typically pales in comparison to new or existing NGCC units, and therefor e it is not particularly cost

- effective as a strategy for lowering carbon emissions. Nevertheless, commenters stated that Georgia may rely on these conversions for compliance purposes, and compared to the coal generation they replace, the converted units

w ill produce lower carbon emissions, at a rate 25 lbs/MWh lower than had the plants remained running on coal.

Commenters observed that the NODA included no instances of conversion within the ERCOT region of the US. Commenters also stated that specific circ umstances contribute to a company's decision to convert to natural gas, and that EPA is not in a position to draw conclusions about how those decisions should be made nationwide. Commenters concluded by stating that if EPA seeks to require conversion under its guidelines, it must provide a concrete proposal and show that strategy is adequately demonstrated for all coal types and all size boilers.

Commenters stated that as part of the Regional Haze Rule ("RHR"), AEPCO has proposed to convert ST2 to natural gas by December 2017. Commenters stated natural gas conversion slightly increases available MWh from the unit, but results in a higher energy cost due to the higher cost of natural gas per MWh compared to coal.

Comment 4: Some commenters assert that natural gas co

- firing or full conversion to gas should part of the BSER.

Response 4 : We disagree with the argument that fuel switching should be included as part of BSER. Please see preamble section V.A.6 of the CPP Final Rule for a general di scussion of non

BSER measures that reduce CO 2 emissions per MWh. Also see the EPA analysis of fuel switching, including its long

- term economic disadvantage versus other measures that are included in the BSER, in chapter 6, Fuel Switching, of the GHG Mitiga tion Measures TSD of the proposal.

The following are summaries of the specific public comments under this comment:166 Commenters stated that conversion to natural gas from existing fossil fuel

- fired utility boilers and IGCC units should be part of the BSER

. C ommenters stated that fuel switching will achieve greater reductions than EPA's current proposal for Building Block 1, and can do so at a cost that is well below the legal standard. Commenters stated that fuel a standard based on natural gas conversion wil l have important non

- air health and environmental benefits and reduce dangerous

co

- pollutant emissions. Commenters provided a table listing currently announced coal to natural gas conversions, a figure detailing the cost for boiler modifications associated with gas conversion, and numerous citations supporting their position. Key issues raised by the commenters are as follows:

• Commenters stated that EPA concluded that coal

- to

- gas conversion is not BSER due to high costs of emission reduction. Commenters sta ted that EPA's analysis does not appropriately characterize the costs. Commenters provided a list of currently announced coal to natural gas conversions (24 such conversions in 19 states expected to be completed by 2020) as evidence that fuel switching is cost

effective and adequately demonstrated. Commenters cited sources that suggested that there could be more than 50 such conversions in 26 states at various stages of planning. Commenters urged EPA to take into account the availability of coal

- to

gas conv ersions when assessing the potential for emission reductions in each state and setting state targets. Commenters mainly cited a white paper from Andover Technology Partners.

• Commenters stated that the technology to convert a coal

- fired utility boiler to b urn natural gas is well

- demonstrated, commercially available, and modestly achievable. Commenters cited various papers in support of this statement.

• Commenters stated that switching to natural gas fuel has a very significant potential for reducing the car bon emissions from fossil fuel

- fired utility boilers and IGCC units. Commenters cited an Andover Technology Partners report that confirms EPA's analysis of conversions for the proposed emission guidelines (i.e., a converted utility boiler firing 100% natur al gas would have an emissions rate of 1,239 lb CO2/MWhnet, representing a 41% reduction in CO2 emissions rate from 100% coal firing).

• Commenters stated that EPA should also consider benefits of co

- pollutant emission reductions that would result from conv erting a unit to burn natural gas and provided brief reasoning for doing so.

• Commenters refuted EPA cost estimates and provided evidence to suggest that EPA's cost estimates are unrealistically high. Commenters stated that EPA should consider criteria poll utant reductions resulting from conversion. Commenters stated that many conversion projects have been recently completed or are currently underway, which shows that the costs are reasonable, and in no way approach the legal standard for a BSER.167 • Commenters stated that most plants only require modest modifications. Commenters stated that typical capital costs for modest modifications are closer to $3/MWh, or 40% lower than EPA's estimate.

• Commenters stated that EPA has significantly underestimated the costs o f coal for many utility boilers by citing national averages instead of specific coal types

. Commenters cited EIA data that shows a range of coal costs from $4.89 per mmBtu to $1.31 per mmBtu

. Commenters stated that this is evidence that natural gas may be cheaper than some sources of coal by 2020, and that the price gap for many sources of coal could narrow considerably.

• Commenters stated that the cost of fuel

- switching boilers is minimal for units that are already designed to burn gas, but the cost of more extensive retrofits is still moderate (and well below the legal standard for BSER) in the context of carbon pollution standards for existing power plants

• Commenters stated EPA's analysis (based on 50 mile pipe line required for conversion) shows that buil ding a long pipeline is generally a relatively small part of the cost of converting a unit to burn natural gas

. Commenters stated that the cost of building a pipeline is likely to be less than EPA assumed because the median distance of a coal

- fired unit fr om a pipeline is 28.3 miles'

- just over half the length of the pipeline in EPA's calculations.

• Commenters stated that EPA did not consider the non

- air quality health and environmental impacts of the systems it identified as potentially representing the BSER . Commenters stated that if EPA had performed the "mandated consideration of the factors enumerated in section 111(a)," the agency would have recognized that switching to natural gas firing at existing units has substantial

non

- air health and environmental benefits. Commenters provided brief examples relating to coal ash and water quality.

Commenters stated that the non

- inclusion of coal

- to

- gas boiler conversions in the BSER is arbitrary and capricious, and fails to meet CAA section 111 mandate to consider the "best" system of emission reductions at EGUs.

Commenters endorsed fuel switching. Commenters stated that their only concern is the ability to secure a firm natural gas supply in a timely manner to meet the interim goals.

Commenters stated that boiler c onversions as well as gas co

- firing can be widely deployed, and significant precedent demonstrates the technical feasibility and cost effectiveness of these options. Commenters cited analysis by the ACSF and EPA to show government support for these project s on a broad scale. Specifically, commenters stated EPA calculated that 40% CO2 reductions can be obtained at those units if run 100% on natural gas.

Commenters stated that EPA must do a more granular assessment of boiler conversions so as to properly cha racterize them as a BSER option. Commenters believed that a more granular, state

by

- state analysis is necessary. Commenters said a state

- by

- state analysis would show that in168 many states, fuel

- switching can be highly cost effective. Commenters stated that E PA has substantially underestimated effective coal prices, thus overstating the cost of boiler conversions and missing the potential for such conversions to contribute to BSER.

Commenters stated that the modifications associated with co

- firing natural gas at a coal

- fired EGU as BSER will likely trigger applicability under EPA's proposed FCAA section section 111(b) rule for modified and reconstructed facilities. The commenters stated that installing natural gas co

- firing capability will increase the overall firing capacity of the unit unless the company makes a corresponding decrease in the coal firing capacity of the unit.

Commenters stated with respect to Building Block 1, if such improvements are possible, they could conceivably subject the load serving entity to application of EPA's other proposed rule, section section 111(b) , which may act to discourage any improvements to the extent they could be made.

Comment 5: Some commenters assert that the U.S. natural gas supply infrastructure is or will be inadequate to timely meet large future increase in demand for natural gas that would result from the CPP Final Rule

. Response 5: The EPA disagrees. We have carefully considered the current and future adequacy of U.S. natural gas supply infrastructure in finalizing this CPP rule. Please see preamble section V.D. of the CPP Final Rule for a discussion of this matter.

The f ollowing are summaries of the specific public comments under this comment:

Commenters agreed that natural gas conversion and co

- firing are not feasible for most coal units, primarily due to the unavailability of an adequate natural gas supply delivery infr astructure nearby and/or costly efficiency and capacity penalties.

Commenter s stated that EPA's premise that a significant portion of the CO2 reductions the proposed rule seeks to achieve can be done through fuel switching from coal to natural gas is based on questionable assumptions regarding natural gas supply, price, and infrastructure availability. Commenters stated that the agency assumes that natural gas infrastructure can be expanded to meet the significant increased demand of electric utilities in a relatively short amount of time. Commenters stated that EPA needs to reexamine these assumptions and adjust its timetables for reducing CO2 emissions from fuel switching.

Commenters stated that it is costly to construct gas pipelines to supply existing co al units that currently do not have sufficient natural gas supply infrastructure in their general area. Commenters stated that the cost for a lateral gas line currently under construction to supply a new TVA NGCC plant is approximately $4MM per mile, or $8 0MM for a 20 mile long pipeline. Commenters stated that where mainline expansion or additional compression is required, costs are tens of millions of dollars higher.169 Comment 6: Commenters stated that the EPA should treat coal

- steam units that switch to na tural gas as coal

- fired units in calculating CO2 emission goals, but not apply building block 1 to them in the calculation. Commenters stated that this approach would credit the voluntary action of converting coal

- fired units to a lower CO2 emitting fuel, acknowledging that the heat rate improvements may no longer be appropriate for the units.

Response 6: In the CPP final rule, the EPA uses data on the primary fuel in the baseline year to categorize a likely affected steam unit as being either a coal

- fire d or oil/gas

- fired unit. Building block 1 is only applied to coal

- fired units. In our calculations, after applying building block 1 to coal steam units, coal and oil/gas steam units are then averaged together in the process of deriving the category

- specifi c fossil steam CO2 emission rate. Because the fossil steam category rate is uniform for all affected steam sources, those fossil steam sources that have switched to a lower CO2 emitting fuel (pre or post 2012) will have an easier time meeting the emission rate. This derivation of a category

- specific emission rate, adopted for the CPP Final Rule, accommodates the commenters’ concerns.

Comment 7: Commenters asserted that the EPA should not encourage increased use of natural gas through fuel switching due to the adverse environmental impacts of natural gas extraction, but should instead emphasize RE and EE.

Response 7: For the EPA’s response to thi s comment, see section V.D of the preamble of the CPP Final Rule and the supporting analysis in the RIA.

The following are summaries of the specific public comments under this comment:

Commenters stated that incentivizing the conversion of coal

- fired plant s to natural gas over the next 16 years would extend the life of old coal plants, create additional incentives for gas extraction, and create disincentives for tor investment in RE and EE. Therefore, commenters agreed that a switch to natural gas firing at coal

- fired plants is inadvisable and should not constitute BSER.

Commenters stated that natural gas extraction has direct and harmful impacts on frontline communities in the U.S. and that a true commitment to emissions reductions means limiting carbon po llution from natural gas sources. However, commenters stated they feel that the proposed standards achieve the opposite by encouraging switching from coal to natural gas.

Comment 8: Commenters stated that the EPA should treat EGUs designed as coal

- fired EGUs and converted to cleaner fuels as coal

- fired EGUs in calculating the goal, but not apply building block 1 to them. Commenters stated that this approach would credit the voluntary action of converting the EGUs to cleaner fuels and also acknowledge that the heat rate improvements may no longer be appropriate for the units.

Response 8: The EPA disagrees with this suggestion. Please see section IV.D. of the CPP Final Rule for a discussion of the rationale for applicability.170 3.7.2 Biomass co

- firing

This subsection addresses the co

- firing of biomass in coal

- fired EGUs as a potential means of reducing CO2 emissions.

Commenters have raised a number of issues related to this subsection which are organized by topics (comments) below. Responses are provided for these topics.

Comment 1 : Commenters raised issues related to co

- firing biomass under the CPP, including its legality as a compliance measure under CAA section 111(d), the acceptability of tire

- derived fuel, and potential implications for compliance with the Cross

- State Air Pollution Rule.

Response 1 : For the EPA’s response to this comment, see sections V.A and VIII.I and K of the preamble of the CPP Final Rule

. The following are summaries of the specific public comments under this comment:

Commenters stated that biomass co

- firing is not a legally permissible method of complying with the CPP and that co

- firing biomass at an affected source will increase the amount (and rate) of CO2 emitted by that source. Commenters stated that the Clean Air Act require s contemporaneous emission reductions at affected sources and does not permit offsets from future, offsite forest sequestration. Key issues raised by the commenters are as follows:

• The CAA section 111(d) program is source

- focused, requiring states to submi t plans that establish standards of performance for certain existing sources. The CPP regulates subpart Da and subpart KKKK sources, which do not include dedicated biomass facilities. Dedicated biomass facilities can only be included in state plans for com pliance with the CPP to the extent that their generation demonstrably displaces generation at the covered sources and, as a result, the covered sources reduce their emissions sufficiently to comply with the standard of performance

• A standard of performance reflects the degree of emission limitation achievable through the application of BSER that the Administrator determines has been adequately demonstrated. Emission reductions attributed to biomass burning EGUs are uncertain, speculative, and dislocated, an d cannot be relied upon by designated facilities for the purpose of CPP compliance. The combustion of biomass at designated facilities does not lead to actual, real

- time emissions reductions at the designated facilities; it cannot be a standard of performa nce, which is defined as the best system of emission reduction. EPA should make explicit in the final CPP that co

- firing biomass at designated facilities is not available for compliance with the emission reduction targets established under the CPP171 • In contr ast with the EGU NSPS, the CPP baseline and target determinations count biomass as emitting zero CO2 emissions when it is burned. EPA must require actual, real

- time emissions reductions at the affected source under the CPP, not net reductions that might oc cur elsewhere years or decades after biomass is initially burned.

• Co

- firing biomass at a covered source typically increases CO2 emissions.

Commenters stated that co

- firing biomass does not produce actual, real

- time emission reductions at the affected sour ce and therefore cannot be relied upon for compliance. Commenters stated that replacing coal with biomass typically increases stack CO emissions. Commenters also stated that the re

- sequestration of emissions both takes years to decades to occur, and does n ot occur at the affected source, and therefore is not a valid form of CO2 reduction

.
Commenters stated that bioenergy does not directly provide mitigation of emissions in the GHG rule. Importantly, commenters stated that neither the NSPS nor the ESPS explicitly offers biomass co

- firing as a means to reduce emissions at coal plants. Additionally, commenters stated all emissions from fossil

- fueled plants, even emissions from co

- fired biomass, are counted in EPA's 2012 baseline emission rates. Commen ters stated that promoting biomass co

- firing would be contrary to Building Block 1, increased efficiency at coal plants, because co

- firing biomass at a coal plant actually decreases facility efficiency and increases CO2 emissions per megawatt

- hour. Comment ers also stated the biomass co

- firing is costly, citing the EPA's estimate of $30

- $80 per ton of CO2

.
Commenters supported EPA's decision to allow states to include tire

- derived

- fuel as a biogenic feedstock in biomass co

- firing plants. Commenters stated t hey hope that the CPP and the PSD program will incentivize the use of tire

- derived

- fuel.

Commenters said that large scale biomass generation applications, particularly more economical

co

- firing applications, could lead to a number of environmental complia nce issues not addressed in the Proposed Rule, e.g., larger biomass co

- firing applications designed to displace existing fossil generation will likely be grid connected and as such, will likely be CSAPR

- eligible. While Louisiana has a number of biomass co

- firing applications today, commenters said that these biomass generators are not CSAPR

- eligible since the power generated is used almost exclusively

on

- site and future grid

- connected biomass applications would put a considerable amount of pressure on Louis iana in meeting its already stringent CSAPR NOX emission requirements. Commenters noted that emissions associated with the transportation of biomass could negate emissions reductions and increase costs.

Comment 2 : Commenters noted that the proposal preamb le stated the intent to adopt a rule "that in all other respects would meet the applicability criteria for coverage under the proposed GHG standards for new fossil fuel

- fired EGUs." Commenters asserted that the proposed rule does not include a provision ex empting a steam generating unit combusting fossil fuel for less than 10% of its heat input during any 3 consecutive years, although a similar provision was included in the section 111(b) new source rule.172 Response 2 : See section IV.D of the preamble of the CPP Final Rule for the EPA’s response to this comment.

Comment 3 : Commenters raised issues about the impacts of biomass co

- firing, including CO2 emissions and secondary impacts.

Response 3 : See sections V.A and VIII.I of the preamble of the CPP Final Ru le and GHG Abatement TSD for the EPA’s response to this comment.

The following are summaries of the specific public comments under this comment:

Commenters requested information about secondary costs associated with a switch to biomass

co

- firing. For example, commenters noted that more trucking will be required to deliver the fuel, which will result in more traffic and air pollution in the surround ing area. Commenters stated that the gathering, chipping, and trucking GHG emissions are not being counted either.

Commenters stated that biomass is less energy efficient than coal, and therefore emits the same
amount of CO2 while providing less energy. A dditionally, commenters stated the fuel is bulkier, and therefore more transportation emissions will be created than would be with coal.

C omment 4 : Commenters questioned the NREL evaluation of biopower that the EPA used in its initial estimates of renewab le energy capacity, particularly as relates to crop residues.

Response 4 : For the EPA’s response to this comment, see Chapter 4 of the GHG Mitigation Measures TSD for supporting the CPP Final Rule

. The following are summaries of the specific public comme nts under this comment:

Commenters noted that the estimate for biopower in the NREL study EPA used in its initial estimates of renewable energy capacity is notably low compared to other technologies, and even so, is probably a significant overestimate, bec ause not only does NREL's estimate include all forms of biopower (including methane collection from human and animal waste) but it considers that all biomass is available to generate combustion

- biopower, rather than being collected for use as ethanol feeds tock. Commenters noted that even with these assumptions, biopower is considered to have only 1.5% the generation potential of onshore wind (500 TWh versus 32,700 TWh).

Commenters noted that the NREL study assumed that crop residues are a likely fuel in th e United States although these materials are notoriously problematic as fuel for combustion biopower. Commenters stated that crop residues make up the bulk of the biomass considered to be potentially available for biomass power generation in the study, out weighing forestry residues by a factor of 2.8 and urban wood by a factor of 5.1. Commenters noted that the problem with this supposedly available crop

- based biomass and the biopower capacity it potentially supports is that very few biomass plants or coal p lants can actually burn crop residues for fuel, as is shown173 by the fact that almost every one of the biomass power plants currently being proposed and built around the country plans to burn wood as fuel. Commenters noted that collection, processing, and st orage of these materials is expensive, a fact that EPA acknowledges in its IPM modeling by attaching not only a $12/dry ton surcharge on all types of biomass for transport, but also a $20/ton surcharge for storage of crop residue

- derived biomass fuels, sin ce they can only be collected at certain times of the year and must be stored in quantity until they are needed.

3.7.3 Other

This subsection addresses aspects of fuel switching in coal

- fired EGUs that do not fit in subsections 3.7.1 and 3.7.2; in many cases, the comments address both natural gas fuel switching and biomass co

- firing. In this subsection the EPA’s use of the term “fuel switching” refers to coal

- fired EGUs that either co

- fire a significant amount of another fuel with coal, or convert to the use of another fuel alone as the boiler fuel.

Commenters have raised a number of issues related to this subsection which are organized by topics (comments) below. Responses are provided for these topics.

Comment 1 : Commenters urged the EPA to recognize t he significant reductions achieved by converting a coal plant to other fuels.

Response 1 : See sections V.A and VIII.I of the final rule preamble of the CPP for the EPA’s response to this comment.

Commenters urged EPA to recognize the significant reductions achieved by converting a coal plant to other fuels, as there are several recent projects underway in Pennsylvania to do just that. Commenters cited for example, one PA Chamber member announced it would be converting a plant in southwestern Pennsylvania to natural gas by May 2016 and another along the New Jersey border to low

- sulfur diesel oil. Commenters stated that according to NRG, the switch to low

- sulfur diesel oil would reduce CO2 emissions at the plant by 93 percent, in addition to significant reduct ions of other pollutants. Commenters stated that at present, EPA's rule does not clearly recognize the emissions reductions of such conversions.

Comment 2 : Commenters stated that EPA should allow co

- firing or repowering of an existing effected unit with lower emitting fuels such as biomass or natural gas to receive full compliance credit. Commenters also stated that the basis for natural gas (or biomass) co

- firing or repowering credit could be determined based on the net improvement relative to the refere nce year established by the state.

Response 2 : See sections V.A and VIII.I of the preamble for CPP Final Rule for the EPA’s response to this comment.174 Comment 3 : Commenters stated that utilities that switch to natural gas or biomass co

- firing should not receive compliance credit.

Response 3 : See sections V.A and VIII.I of the preamble for CPP Final Rule for the EPA’s response to this comment.

The following are summaries of the specific public comments under this comment:

Commenters stated that utilities t hat switch to natural gas or biomass co

- firing should not receive compliance credit, as these fuel types still emit unacceptable levels of GHGs. Commenters also stated that lifecycle of these fuels also contributes to GHG emissions which further makes them unacceptable.

Commenters stated that fuel switching may have unintended consequences and the carbon that would not be captured and measured, as well as the inefficiencies in delivery of energy efficiency services that may come by excluding efficiency gai ns from gas and other heating fuels under the rule.

Comment 4 : Commenters stated that the EPA should create a subcategory for EGUs that use coal refuse since they cannot switch fuel and they provide other environmental benefits.

Response 4 : The EPA recognizes the continuing value of cleaning up coal refuse piles. We disagree, however, with the recommendation that EGUs burning coal refuse should be treated differently than other coal

- steam EGUs under the CPP Final R ule. The CPP Final R ule does not require any particular EGU to switch fuels, to co

- fire another fuel, or to reduce or cease operation. The EPA notes that while the steam EGUs of interest to the commenters do have these options available to them for CO2 reduction, they also have avail able to them the same wide range of heat rate improvement measures that other coal

- fired EGUs have available for potential CO2 reduction. Please see Chapter 2 of the GHG Mitigation TSD for a detailed discussion of heat rate improvement measures.

The follow ing are summaries of the specific public comments under this comment:

Commenters stated that these plants were created to serve as a zero

- cost way to rid Pennsylvania's landscape of waste coal piles. Commenters explained that Pennsylvania currently has 13 plants that convert waste coal into energy, and that these plants cannot fuel switch. Commenters noted however, that these plants have served to improve the environment in Pennsylvania as they have prevented acid mine drainage and allowed for the reclamati on of thousands of acres of previously

- damaged land and the restoration of hundreds of miles of polluted streams. Commenters recommended that EPA create a subcategory for electric generating units that use coal refuse, and thus would not switch to fuel wit h a higher Btu rating, and recalculate a goal emission rate specific to these plants so they may continue to do the essential task of cleaning up coal refuse piles.175 3.8 CARBON CAPTURE & STORAGE

This section discusses the implementation of carbon capture a nd storage (CCS) as an emissions reduction method. As discussed in the preamble of the CCP Final Rule (see

, specifically

, section V.A.2.d.(1) ), t he EPA is not identifying CCS at coal

- fired steam EGUs as part of the BSER, but it remains a control measure th at some affected EGUs may be expected to implement. We have organized the comments in this section under 7 subsections, 3.8.1 to 3.8. 7

. Responses to the comment topics of these subsections are discussed below along with summaries of the specific public comments.

Commenters have raised a number of issues related to the subsection which are organized by topics (comments) below. Responses a re also provided for these topics. (Below the response, comment summaries are noted.)

3.8.1 Post

- combustion capture

Comment 1: EPA Should f ind that p artial CCS is an a lternative a dequately d emonstrated s ystem of e mission r eduction

Response 1: The se comments recite much of the applicable case law related to section 111 standards of performance

. The EPA has not ruled out use of CCS as a compliance option for existing sources, but has found that the existing power plant fleet is so disparate with respect to such factors as age, location, size, and available space that making a nationally

- applicable BSER determination for CCS for existing sources is unwarranted.

The following are summaries of the specific public comments under this comment:

Commente rs stated, although EPA has properly identified the CPP's flexible Building Block system as the "best" system of emission reduction, partial carbon capture and storage (CCS) is an adequately demonstrated alternative that would be the BSER in the absence of the Building Block system. Commenters said, a partial CCS standard similar to the standard proposed for new EGUs would reduce CO2 emissions from super critical pulverized coal plants by 33 percent and from IGCC plants by18 percent

- far exceeding the redu ctions that could be achieved by the 6% heat rate improvement under Building Block 1

- and would also achieve significantly greater reductions of co

- pollutants. Commenters said, in the final rule, EPA should provide a more detailed assessment of partial CC S as an alternative BSER. Commenters said, partial CCS is a statutorily satisfactory system of emissions reduction that achieves far greater emissions reductions than Building Block 1 (heat rate improvements) alone.

Commenters stated, as explained below, p artial CCS satisfies the statutory criteria for BSER:

CCS is adequately demonstrated for retrofit to existing EGUs.176 Commenters stated, as EPA documented at length in the TSD for the proposed carbon pollution standards for new EGUs, the individual technolog ies used in CCS systems have been available for decades and have been applied at a commercial scale in other industrial sectors. Commenters said, utilities have made significant progress towards applying this technology to coal

- fired EGUs, including severa l successful demonstration

- scale projects at existing facilities. Commenters said, and in October 2014, the Canadian utility SaskPower activated the first commercial

- scale CCS project for the power sector: a rebuilt 139 MW unit at its Boundary Dam plant, e quipped with CCS technology capable of capturing 90 percent of the unit's CO2 emissions.

Commenters stated, coal

- fired power plants designed for demonstration

- scale CCS application include AES's coal

- fired Warrior Run (Cumberland, MD) (capturing 110,000 me tric tons CO2 /year) and Shady Point (Panama, OK) (capturing 66,000 metric tons CO2 /year), both equipped with amine scrubbers designed to process a slip stream of the plant's flue gas. Commenters said, SaskPower's Boundary Dam plant in Canada, a coal

- fire d power plant retro

- fitted for CCS at commercial scale, in the testing stage at the time of the proposed rule, came online in October 2014. Commenters said, Mississippi Power's Kemper County Energy Facility, a second coal

fired power plant designed to empl oy CCS at a commercial scale, is expected to begin operation in 2016. Commenters said, in July 2014, retrofit construction began on the Petra Nova Carbon Capture Project at the existing 240 MW W.A. Parish coal

- fired power plant near Houston, Texas; capture at a rate of 1.6 million tons CO2 per year will begin by the end of 2016.

Commenters stated, the Boundary Dan project will result in the capture of over one million metric tons of CO2 per year, and was undertaken in part to comply with Canadian emission

s tandards for existing EGUs Commenters said, although SaskPower has yet to release official data since operations began, SaskPower CEO Robert Watson has stated that the carbon capture equipment is performing as expected with respect to the amount of power r equired for operation of the equipment, and noted that SaskPower anticipates achieving the full 90% capture rate "in not too long at all."

Commenters stated, SaskPower's currently operational, commercial scale Boundary Dam plant project

- along with other evidence in the record for the proposed NSPS for new EGUs

- shows that partial carbon capture is adequately demonstrated for existing coal

- fired power plants. Commenters said, "adequately demonstrated" does not mean that all existing sources are able to

me et the requirement, see Nat'l Asphalt Pavement Ass'n, 539 F.2d at 785

- 86, nor does it require the available technology to be in "actual routine use" at the time of the rulemaking. See Portland Cement Ass'n v. Ruckleshaus, 486 F.2d 375, 391 (D.C. Cir. 1973) ("Portland Cement I"). Commenters said, rather,

[t]he Administrator may make a projection based on existing technology, though that projection is subject to the restraints of reasonableness and cannot be based on "crystal ball" inquiry.

[T]he question of availability is partially dependent on "lead time", the time in which the technology will have to be available.

If actual tests are not relied on, but instead a prediction is made, its validity rests on the reliability of [the] prediction and the nature o f [the] assumption.177 Portland Cement I, 486 F.2d at 391

- 92 (citing and quoting Int'l Harvester v. Ruckelshaus, 478 F.2d 615, 629 (D.C. Cir. 1973)). Commenters said, moreover, EPA can "extrapolat[e]" a technology's performance in other industries", and look beyond domestic facilities to those used abroad. Lignite Energy Council, 198 F.3d 930, 934 n.3 (D.C. Cir. 1999). Commenters said, the Portland Cement I court found that the term "adequately demonstrated" required a showing by EPA "that there will be 'avail able technology' during the regulated future." Portland Cement I, 486 F.2d at 391 (emphasis added). Commenters said, thus the question is whether the technology will be available at the time that implementation is required.

Commenters stated, EPA can and m ust encourage new and less

- polluting technologies through the standards it sets under section 111. Commenters said, the legislative history of section 111 and the relevant case law affirm the technology

- forcing nature of the statute. Commenters said, for i nstance, the 1977 Senate Report discusses the need "to assure the use of available technology and to stimulate the development of new technology." S. Rep. No. 95

- 127 at 171. Commenters said, to that end, "[t]he statutory factors which EPA must weigh [when setting performance standards] are broadly defined and include within their ambit sub

- factors such as technological innovation." Sierra Club, 657 F.2d 298, 346 (D.C. Cir. 1981). Commenters said, in Sierra Club, the court explained: "Recognizing that the Cl ean Air Act is a technology

- forcing statute, we believe EPA does have authority to hold the industry to a standard of improved design and operational advances, so long as there is substantial evidence that such improvements are feasible and will produce th e improved performance necessary to meet the standard". As a result, we uphold EPA's judgment that the standard can be set at a level that is higher than has been actually demonstrated over the long term by currently operating lime scrubbers at plants burn ing high sulfur coal." see also Portland Cement Ass'n v. EPA ("Portland Cement III"), 665 F.3d 177, 190 (D.C. Cir. 2011) (EPA properly based the NSPS for new cement kilns on a recent and more efficient model, even though many older kilns still existed that did not utilize the same technology). Commenters said, these standards should reflect the use of the "best" control options, including those achieving the deepest reductions, consistent with Congress's intent to encourage technological advancement in cont rols.

Commenters stated, the operational status of the Boundary Dam project demonstrates the viability of large scale CO2 capture and shows that CCS can be accomplished on a commercial scale, including as a retro

- fit to an existing plant. Commenters said, furthermore, the current status of the Boundary Dam project and the development rate of CCS technology evinced by the record support the conclusion that retrofitted CCS technology will be more widely available for commercial use by 2020, when the rule's re quirements must be implemented.

Commenters stated, with respect to the CO2 transportation required to facilitate storage where nearby geologic sequestration is not feasible, EPA has properly concluded that the necessary technology is adequately demonstrate d and feasible. See 79 Fed. Reg at 1472. Commenters said, as EPA notes, CO2 has been transported via pipelines in the U.S. for almost 40 years, and approximately 50 million metric tons of CO2 are transported each year through 3,600 miles of pipelines. See I d. Commenters said, EPA has determined that 95 percent of the 500 largest CO2 point sources are within 50 miles of a possible geologic sequestration site. See I d.

Commenters stated, similarly, with respect to the storage component of CCS, as EPA properly identified in the proposal for NSPS for GHG emissions from new EGUs, geologic sequestration178 of CO2 is available and adequately demonstrated. Commenters said, EPA has cited to numerous CO2 commercial storage projects as well as field studies that demonstrat e the feasibility of geologic sequestration. See 79 Fed. Reg. at 1472

- 74. Commenters said, for example, since 1996 the Sleipner natural gas processing project in the North Sea has separated CO2 from natural gas and sequestered Mtpa of CO2 in an offshore de ep saline reservoir. Commenters said, additionally, the oil and natural gas industry in the United States and abroad has five decades of experience in injecting captured CO2 into geologic formations. Commenters said, Department of Energy ("DOE") studies in dicate that the U.S. has ample CO2 storage potential. See 79 Fed. Reg. at 1473. Commenters said, as mentioned above, the majority of existing coal

- fired power plants are located in regions where there is a high likelihood of nearby geologic storage availab ility.

. Commenters stated, in the proposed rule, EPA asserts that it will not propose partial CCS as the BSER because the costs would be "substantial" and affect electricity prices. Commenters said, yet even if the costs of retro

- fitting the existing EGU fleet for partial CCS would be "substantial" and affect electricity prices, those costs will be within EPA's discretion under section 111 as long as they are not "exorbitant" or "more than the industry can bear." See Portland Cement I, 486 F.2d at 391; Ess ex Chemical Corp., 486 F.2d 427, 433 (D.C. Cir. 1973); Sierra Club, 657 F.2d 298, 383 (D.C. Cir. 1981); Lignite Energy Council, 198 F.3d at 933. Commenters said, consequently, EPA is not foreclosed from determining that CCS is the BSER. Commenters said, fu rthermore, CCS costs may be defrayed by the use of captured CO2 for enhanced oil recovery, or reduced by implementation of partial CCS at lower proportions of capture.

Commenters stated, section 111(a)(1) of the CAA directs EPA to include costs among the f actors it considers when determining the BSER. Commenters said, in a line of cases spanning several decades, the D.C. Circuit held that the statute is satisfied as long as the costs of the BSER are not "excessive" or "exorbitant." See Portland Cement I, 48 6 F.2d at 391; Essex Chemical Corp., 486 F.2d at 433; Sierra Club, 657 F.2d at 383; Lignite Energy Council, 198 F.3d at 933. Commenters said, section 111 allows EPA to take a broad view of the costs of the proposed standard at the national and regional lev el, which includes consideration of the pollution benefits that would be achieved, the avoided costs of carbon pollution on society as well as the co

- benefits of reducing harmful PM2.5 and ozone pollution. See Sierra Club, 657 F.2d at 330. Commenters said, when setting a standard of performance under section 111, "EPA has authority to weigh cost, energy, and environmental impacts in the broadest sense at the national and regional levels and over time as opposed to simply at the plant level in the immediate present." Sierra Club, 657 F.2d at 330. Commenters said, notably, the D.C. Circuit has never upheld a challenge to a section 111 standard based on cost. 79 Fed. Reg. at 1464. Commenters said, for example, in Portland Cement I, the court upheld an NSPS for particulate matter emissions, even though control technologies amounted to roughly 12 percent of the capital investment for an entire new plant and consumed five to seven percent of a plant's total operating costs. 486 F.2d 375, 387

- 88. Commenters said, li kewise, the court upheld particulate matter ("PM") standards that were anticipated to increase the cost of cement by one to seven percent, with little projected decrease in demand. Portland Cement Ass'n v. EPA, 665 F.3d 177, 191 (D.C. Cir. 2011); see also 73 Fed. Reg. 34,072, 34,077, 34,086 (June 16, 2008). Commenters said, with respect to the electricity generating industry, the Lignite Energy Council court held that a two percent increase in the cost of producing electricity179 was not exorbitant, and upheld the 1997 nitrogen oxides ("NOx") NSPS for EGUs and industrial boilers. See 198 F.3d at 933 (62 Fed. Reg. 36, 948, 36,958 (July 9, 1997)).

Commenters stated, in the CPP proposal, EPA explains that the costs of CCS may be "substantial" and potentially affec t electricity prices: [T]he cost of integrating a retrofit CCS system into an existing facility would be expected to be substantial, and some existing EGUs might have space limitations and thus might not be able to accommodate the expansion needed to insta ll CCS. Further, the aggregated costs of applying CCS as a component of the BSER for the large number of existing fossil fuel

- fired steam EGUs would be substantial and would be expected to affect the cost and potentially the supply of electricity on a nati onal basis. For these reasons, although some individual facilities may find implementation of CCS to be a viable CO2 mitigation option. EPA is not proposing CCS as a component of the BSER[.] See 79 Fed. Reg. at 34,857.

Commenters said, yet such cost impac ts

- in the absence of an alternative system of emission reduction that is less costly and achieves very significant emission reductions

- may well not be outside of the appropriate bounds of a best system of emission reduction analysis.

Commenters stated, furthermore, in evaluating the costs of partial CCS, EPA has discretion to include a consideration of revenue generated as a result of injection of CO2 for enhanced oil recovery (EOR) operations. Commenters said, section 111 allows a broad consideration o f costs, including the sale of byproducts, and EPA may properly take the possibility of EOR sales into account when evaluating the costs of the proposed performance standard. See Sierra Club v. Costle, 657 F.2d at 330 ("[S]ection 111 ... gives EPA authorit y when determining the best technological system to weigh cost, energy, and environmental impacts in the broadest sense ... over time."). Commenters said, they note, however, that ensuring permanent sequestration of CO2 injected for EOR would be essential to implementing CCS as the BSER, as EOR operations have not been designed for this purpose historically. Commenters said, nonetheless, because EPA's assessment of the costs of CCS may properly include the potential for EOR at some subset of the fleet, the costs of CCS would, in some locations, be reduced by this source of revenue generation.

Commenters stated, the D.C. Circuit has held that the agency has authority to evaluate all of the statutory factors in a BSER determination "in the broadest possible se nse," and to consider costs "at the national and regional levels and over time as opposed to simply at the plant level in the immediate present." Sierra Club, 657 F.2d at 331. Commenters said, given that, it is appropriate for EPA to consider revenue strea ms from the co

- production of CO2 in its determination that carbon capture and storage ("CCS") is BSER for coal

- fired EGUs. Commenters said, furthermore, as EPA asserts, if costs of disposal of byproducts must be taken into account during cost analysis, rev enue from the sale of economically valuable products as a co

- benefit of achieving a particular performance standard should also be taken into account. See 79 Fed. Reg. at 1,464. Commenters said, to the extent that the sale of captured CO2 may generate reve nues for plant operators, those revenues should be factored into a determination of the proposed rule's
costs.
Commenters stated, EPA's prior actions are consistent with the notion that byproduct revenue may be considered when the agency sets a performance standard. Commenters said, for example,180 in 2012, EPA and the National Highway Traffic Safety Administration fi nalized new fuel economy standards for light

- duty vehicles. See 77 Fed. Reg. 62,624 (Oct. 15, 2012). Commenters said, in its cost analysis, the agencies determined that the benefits that would result from more stringent standards would "far outweigh higher vehicle costs" to consumers, largely due to the 170 billion gallons of fuel that would be saved throughout the lives of vehicles sold over an eight

- year period. Id. At 62,629, 62,631. Commenters said, from a macroeconomic standpoint, these savings are fun ctionally indistinguishable from the revenue that would accrue if those 170 billion gallons of fuel were a direct byproduct of the new technology, rather than the amount saved due to reduced demand. Commenters said, that same year, EPA analyzed revenues fr om the sale of natural gas and condensate recovered through the installation of pollution controls when describing costs associated with the NSPS for oil and natural gas production. See 77 Fed. Reg. 49,490, 49,534 (Aug. 16, 2012) (estimating that the propo sed standards would save approximately $11 million annually if revenues from additional recovery were considered).

Commenters stated, finally, EPA could employ flexibility measures that would reduce the cost of CCS. Commenters said, for example, to reduce overall costs in the initial years following CCS technology installation, EPA could incorporate a gradual ramp

- up rate in the percentage of capture that would allow for lower operational costs. Commenters said, a gradual introduction of CCS would also allo w the industry to realize reductions in cost and improvements in performance that are likely to result from increasing familiarity with and development of CCS technology. Commenters said, for example, SaskPower executives have stated that they expect to

re trofit additional coal

- fired EGUs with CCS, and that the next such project will likely have 20

- 30% lower capital costs than Boundary Dam. Commenters said, studies of CCS technology development have also estimated that the cost of electricity from CCS

- equip ped plants would likely decrease by 10

- 18% after approximately 100 GW of CCS capacity has been installed.

Commenters stated, in summary, EPA may ultimately determine that the costs of CCS, though significant, are nonetheless within the appropriate bounds, particularly in light of opportunities to defray costs through EOR, and to adjust the proportion of capture assumed in setting the standard.

Commenters stated, although the preamble to the proposed rule appears to reject partial CCS on the ground of cost alone, the GHG Abatement Measures TSD makes it clear that EPA also based its decision on the conclusion that CCS "may not be technically or logistically feasible in a number of cases." Commenters said, whereas the preamble appears to treat the spatial
requ irements and geographic factors relevant to CCS as considerations that will inflate the cost of CCS, the TSD addresses these concerns as part of an analysis of feasibility.

Commenters stated, in the TSD, EPA explains that: Some existing facilities are loca ted in areas where CO2 storage is not geologically favorable and are not near an existing CO2 pipeline. Integrating a retrofit CCS system into an existing facility is much more challenging. Some existing sources have a limited footprint and may not have th e land available to add partial CCS system. Integration of the existing steam system with a retrofit CCS system can be particularly challenging.

Commenters stated, although EPA states that CCS may not be feasible "in a number of cases," such a consideratio n does not bar the Agency from selecting CCS as the BSER because section181 111 does not require EPA to find that all existing sources be able to meet the requirement. See Nat'l Asphalt Pavement Ass'n, 539 F.2d at 785

- 86. Commenters said, to the extent that E PA is asserting that these site

- specific concerns show that CCS is not adequately demonstrated for any retrofit applications, such a conclusion would be unwarranted because it is well established that an emission reductions system can be "adequately demons trated" even though some existing units may not be able to meet the resultant standard. See I d.

Commenters stated, furthermore the difficulty that some existing sources might have in adopting CCS due to site

- specific spatial constraints or distance from CO 2 pipelines or geologic units appropriate for sequestration are properly assessed as part of the projected cost of CCS rather than as technical feasibility. Cf. Honeywell Int'l, Inc. v. EPA, 374 F.3d 1363, 1372 (D.C. Cir. 2004) (finding that EPA decision t o allow certain businesses to continue to use certain chemical agents on "technical feasibility" ground that it might be burdensome to those businesses to switch to another agent was actually a decision based on cost.) Commenters said, as the D.C. Circuit has stated, "it is often possible to fit a round peg in a square hole if enough money is spent to make the round peg fit. In other words, a given change in manufacturing technique may be 'technically infeasible' only as compared to some baseline of what it would cost to change the technique." Id. Commenters said, for example, though the current footprint of a particular plant might not be large enough to accommodate CCS, it might nonetheless be feasible for the plant to expand its footprint by acquiring adj acent land at a cost that would not be exorbitant. Commenters said, thus, rather than speculating that some number of plants may have spatial and geographic factors that would make CCS "infeasible," EPA should assess how widespread such constraints are and factor that information into its determination regarding the cost of CCS.

Commenters stated, in summary, because the case law makes clear that the BSER need not be feasibly applied at every source, EPA is not required to base its evaluation of the feasibi lity or cost of CCS on some subset of facilities where source

- specific spatial or geographic constraints would prohibit its use. Commenters said, although spatial and geographic factors may generally increase the average cost of CCS, those costs will not n ecessarily be "exorbitant" or "more than the industry can bear." Commenters said, consequently, EPA could ultimately conclude that CCS is a potential BSER (though inferior to the flexible, system

- based BSER currently proposed).

Commenters stated, in additi on, EPA can and should take into account likely reductions in the cost of CCS that will accompany increasing deployment of the technology. Commenters said, as noted above, utilities such as SaskPower and researchers in the field of pollution control have
p redicted that the costs of CCS will decline significantly as the industry gains experience with the technology

- just as has occurred with well

- established technologies for power plants, such as flue gas desulfurization and selective catalytic reduction.

C ommenters stated, finally, it is noteworthy that because EPA has discretion to sub

- categorize sources, the Agency could distinguish between sources based on proximity to EOR or other spatial or geographic factors. Commenters said, by subcategorizing in thi s way, EPA could find that partial CCS is the BSER for the sub

- category of plants where physical constraints would not impose excessive costs.

Commenters stated, section 111 makes clear that EPA must consider the degree of emission limitation achieved, as well as the costs of achieving it, when formulating a performance182 standard. 42 U.S.C. Section 7411(a)(1). Commenters said, this does not require the application of a strict cost

- benefit test; rather, reviewing courts have upheld performance standards so lo ng as the costs are not exorbitant (i.e., too high for the industry to bear) in light of the pollution reduction benefits they will yield. Commenters said, for example, in Sierra Club, the court upheld sulfur dioxide ("SO2") standards that would cost indus try tens of billions of dollars between 1987 and 1995, but would provide significant benefits, including 100,000

- 200,000 tons of SO2 emission reductions per year, cost savings of over $1 billion per year, and a 200,000 barrel

- per

- day reduction in oil con sumption. 657 F.2d at 314, 327

- 28.

Commenters stated, while there exists no dollars

- per

- ton

- removed cost

- effectiveness level to serve as a "rule of thumb," the Portland Cement III court upheld PM standards for Portland cement plants that EPA had determined were "well within the range of cost

- effectiveness" at about $3,969 per ton of PM emissions removed. 665 F.3d 191; see also 73 Fed. Reg. 34,072, 34,076

- 077 (June 16, 2008) (discussing costs per ton removed by EPA's BSER for PM, and noting that the agency h ad previously deemed PM regulations for EGUs to be reasonably cost

effective at $8,400 per ton of PM removed). Commenters said, similarly, in Lignite, the court upheld NOx performance standards that would cost $1,770 per ton removed, despite the availabili ty of cheaper but less protective alternatives advocated by industry petitioners. 198 F.3d at 933; 62 Fed. Reg. 36,948, 36,953 (July 9, 1997).

Commenters stated, partial CCS can achieve emission reductions that are far greater than reductions generated by other alternative standards, such as a standard based on heat rate improvements alone. Commenters said, in the absence of a flexible Building Block scheme that can provide comparable CO2 reductions more cost effectively, EPA could conclude that partial CCS would be the BSER because those reductions are considerable, the technology is adequately demonstrated for existing coal

- fired power plants, and the costs have not been shown to be outside the range allowable under statute as elucidated by the case law. C ommenters said, in evaluating alternative systems of emission reductions, EPA must consider the degree of the pollution reduction benefits that a proposed standard would achieve along with the costs of achieving it. See Sierra Club, 657 F.2d at 314, 327

- 28 (upholding costly SO2 standards that would provide significant pollution benefits); Essex Chem. Corp., 486 F.2d at 437 (acid mist standards were reasoned and cost benefit analysis was not required). Commenters said, a partial CCS standard would achieve si gnificant reductions in CO2 emissions that are urgently needed in the power sector. Commenters said, a partial CCS standard similar to the standard proposed for new EGUs would reduce CO2 emissions from super critical pulverized coal plants by 33 percent (6 00 lb CO2/MWh net) and from IGCC plants by18 percent (300 lb CO2/MWh net). Commenters said, such a partial CCS standard would also result in additional co

- benefits of reducing NOx, SO2, and PM2.5. Commenters said, these emissions reductions far exceed thos e anticipated to result from, for example, the 6% heat rate improvement under Building Block 1. Commenters said, consequently, partial CCS is a superior system of emission reduction compared to alternative systems of emission reduction, and would be the BS ER if the building block approach proposed by EPA were not available.

Comment 2: Commenters stated that CCS is not adequately demonstrated.183 Response 2: The EPA is not identifying CCS at coal

- fired steam EGUs as part of the BSER, but it remains a control measure that some affected EGUs may be expected to implement. However,
t he EPA disagrees that CCS technologies are not proven. The components of CCS

– cap ture, compression, transportation, and storage have been used for decades in a variety of industries

– including the power sector. Both post

- and pre

- combustion CCS are demonstrated in full scale commercial operation

. Reference sections V.D. and E. of the preamble and supporting documents of the companion section 111(b) standards for GHG emissions from new, modified and reconstructed sources

. The EPA further notes that CCS was not proposed to be

– or determined to be at final

– part of the BSER for existing fossil fuel

- fired EGUs. See section V.A of the final rule preamble of the CPP and Chapter 5 of the GHG Mitigation Measures TSD for CPP Final Rule for EPA’s response to this comment.

The following are summaries of the specific public comments under this c omment:

Commenters said that, EPA is required to consider cost of achieving emissions limitations for a standard of performance for a new source within the source category under Section 111. Commenters said that EPA focused on comparative cost across sourc e categories instead of within the source category. Commenters gave the example of coal fired units have a limit without Carbon Capture and Sequestration (CCS), limits with various levels of partial CCS, a limit with "full" CCS. Commenters said the Propose d Rule compared partial CCS at coal fired EUGs cost to another source category like combined cycle natural gas. Commenters said the Proposed Rule also compared partial CCS to another source technologies that are not even regulated under Section 111 (nuclea r, biomass, geothermal, onshore and offshore wind, solar PV and solar thermal). Commenters said the construction is not complete and operational at a partial CCS; therefore, the actual costs of projects are completely unknown at this time.

Commenters said that EPA features four CCS projects (at varying stages of development) to make the case that the technology is "adequately demonstrated." Commenters said that the 2005 Energy Policy Act prohibits EPA from basing an "adequately demonstrated" determination o n CCS projects that received subsidies under the Act. Commenters said, three of the projects EPA cites did receive such subsidies. Commenters said the fourth project is also subsidized, albeit by the Canadian government. Commenters said that subsidized pro jects are an inappropriate basis for deeming CCS to be adequately demonstrated.
Commenters said that it is also the viewpoint of Southern Company, which received a $270 million Department of Energy (DOE) grant for its Kemper, Mississippi, CCS project. Comm enters said that Southern Company spokesman Tim Lejedal stated in March: "The Kemper County Energy Facility should not serve as a primary basis for new emissions standards impacting on all new coal

- fired power plants." Commenters said that he also cautione d: "The revised new source performance standards would essentially eliminate coal as a future generation option."

Commenters said that, the Proposed Rule states that EPA has not proposed to require Carbon Capture and sequestration (CCS) at existing facilit ies to be retrofitted because of technical challenges and substantial costs. Commenters said the proposed rule requests comment on whether to require full or partial CCS on existing EGUs, and whether partial CCS is appropriate for States to include in thei r plans to meet the emissions reduction requirements

. Commenters184 said that CCS is not a "BSER adequately demonstrated" under the CAA, and therefore neither standards in a proposed 111(d) rule, nor implementation, should be based on an assumption that CCS w ill be deployed.

Commenters said that, Section 111 of the CAA requires the EPA to implement the "BSER ... adequately demonstrated." Commenters said that, the meaning of this term has been interpreted by the Courts to refer to "one which has been shown to b e reasonably reliable, reasonably efficient, and which can reasonably be expected to serve the interests of pollution control without becoming exorbitantly costly in an economic or environmental way." Commenters said that in order to show adequate demonstr ation, the courts have held that the EPA has the burden to "(1) identify variable conditions that might contribute to the amount of expected emissions, and (2) establish that the test data relied on by the agency are representative of potential industry

- wi de performance, given the range of variables that affect the achievability of the standard. Commenters said the Courts have repeatedly stated performance standards set under section 111 are meant to be "for the industry as a whole." Commenters said, given this standard CCS is simply not adequately demonstrated, nor has the EPA met its burden to show that industry wide performance is achievable over the range of geological variables or variable types of fuel.

Commenters said that, the Proposed Rule points to three sites where partial CCS is being developed or employed. Commenters said that EPA points to three sites as examples of partial CCS being "demonstrated" while at the same time noting that Plant Barry is a pilot

- scale site and the installation of the t echnology at the W.A. Parish facility has yet to be completed. Commenters noted that Plant Barry is a 2,657 MW capacity facility, and the CCS pilot test is being conducted on a 25 MW slipstream, or an emissions output representing less than 1% of the plant 's capacity. Commenters said that the third site, Boundary Dam facility, is the only full

- scale capture site in operation in the world, but its carbon capture equipment has been operating only since October of this year. Commenters stated this offers very little evidence of reliability or efficiency on which to legally base a new rule.

Commenters said that, the Department of Energy ("DOE") continues to lead the domestic CCS research through the National Energy Technology Laboratory ("NETL"). Commenters said that in its most recent technology readiness assessment, zero of the 158 carbon capture projects funded through NETL have reached a technology readiness assessment level of a seven out of nine. Commenters said that level seven requires "demonstration of a n actual system prototype in a relevant environment" that shows the "complete technology has undergone large pilot

- scale testing using actual flue gas composition at a scale equivalent to approximately 25,000

- 625,000 scfm." Commenters said that carbon capt ure has yet to reach advanced preliminary scale

- up stages, let alone be "reasonably reliable" or "reasonably efficient."

Commenters said that, only one new large

- scale coal

- fired power plant in the world currently under construction is being built with CCS

- Southern Company's 582

- MW Kemper County Energy Facility ("Kemper") in Mississippi. Commenters said that, the Constructed with substantial financial support from the federal government, the technology developed for Kemper is specific to lignite, and is no t applicable to the other steam coal types used to power the majority of the U.S. coal fleet, nor applicable with the use of natural gas. Commenters said that, other than Boundary Dam and Kemper, there are only two facilities in the U.S. attempting to depl oy CCS on a commercial scale. Commenters said that, both have been approved to receive185 substantial government assistance, which Congress has specified makes them ineligible to serve as a basis for an emission standard. Commenters said that, EPA has not eve n attempted to "identify variable conditions that might contribute to the amount of expected emissions" from facilities deploying CCS, nor is it possible for the agency to "establish that the test data relied on by the agency are representative of potentia l industry

- wide performance, given the range of variables that affect the achievability of the standard." CCS is at most a nascent, untested emissions reduction system. At a minimum, it requires: (1) the use of largely

- undeveloped technology to capture CO2 emissions; and (2) access to relatively rare geological formations that are capable of storing CO2. For r easons set out at length in comments EPA received in response to the Proposed New Source Rule, neither the capture nor the storage component of CCS has been "adequately demonstrated" to date.

Commenters stated the EPA's current proposal to regulate new f ossil fuel

- fired electric utility units under section section 111(b) of the Act is based on their finding that carbon capture and sequestration (CCS) has been adequately demonstrated. Commenters state d that CCS has not been adequately demonstrated. Moreove r, the commenters said there is uncertainty with respect to even the feasibility of the separation technology on this scale as well as continued concerns about the availability of geologic formations for subsequent sequestration.

Commenters said that, the second component of CCS

- storage

- has even less evidence of large

scale feasibility than carbon capture. Commenters stated that in order to include CCS in a rule for existing generation facilities, the EPA must show that storage has been adequately demo nstrated for all sources that will have to comply under the rule, which is all existing coal

fired EGUs.

Commenters stated that, various commencers have noted the large capacity of potential geologic storage formations in the United States. Commenters said that while these formations exhibit the general characteristics that would make them suitable for storage, almost none have been tested on a scale sufficient to base a decision to undertake decades of large

- scale storage.

Commenters said that, under secti on 111, the EPA is prohibited by law from "giving a competitive advantage to one State over another in attracting industry." Commenters said that for the purpose of CCS this would require there to be storage options that are adequately distributed
across t he U.S. Commenters said they provide gaudy estimates of the amount of geologic storage capacity available for CO2 storage and commenters showed that as many as 12 States have less than a single year's worth of assessed storage capacity of any type for the current major sources of CO2 emissions within their borders, based on DOE's high estimate of storage capacity for the State. Commenters said that sixteen states have less than 20 years' worth of storage capacity, based on the high estimate, which is only h alf or less of the operating life of a coal

- fired power plant. Commenters said that this includes several large western States including Arizona, Idaho, and Nevada. Commenters said that the CO2 would need to be piped elsewhere. Commenters said that to furt her complicate the matter, a substantial portion of existing CO2 pipelines are not "common carrier" lines open to anyone's use. Commenters said that the EPA has not addressed any of these issues in this proposed rulemaking.

Commenters said that, the CCS t echnology itself fails to meet the definition of being adequately demonstrated. Commenters said that one million tons per year of CO2 storage is the amount186 generally considered to be "large

- scale." Commenters said that in only three locations in the world has large

- scale storage been conducted in a saline or other non

- enhanced oil recovery ("EOR") formation: (1) the Sleipner gas processing facility in the North Sea; (2) the Snohvit gas processing facility in the North Sea; and (3) the In Salah gas processin g facility in Algeria. Commenters said that only one of these three examples is what could be considered "successful" from the standpoint of someone seeking to arrange for 30 to 50 years' worth of CO2 storage (though each may have been successful when meas ured by the objectives of the project operators). Commenters said that Sleipner has stored successfully 14 million tons of CO2 since it began operation in 1996. Commenters said that in Salah ceased operations in 2011 after seven years of operation. Comment ers said that formation pressure increased to the point where injections no longer could continue without concern for breaking the caprock containing the CO2. Commenters said that Snohvit has suspended operations on several occasions to allow reservoir pre ssure to subside following periods of injection. Commenters said that a report from the fall of 2013 states, "Since the start of CO2 injection, the injection well pressure has risen at a rate faster than what is sustainable for a 25

- years expected lifetime of the project." Commenters said that a 33% success rate is not a sufficient basis to show that large

- scale saline storage is "reasonably reliable."

Commenters said that, permitting of storage wells is also an important concern for large

- scale implementat ion of CCS. Commenters said that a Class VI well permit is required before storage of CO2. Commenters said that just this year, the EPA approved its very first Class VI permits for storage of CO2 captured from a coal

- fired power plants

. Commenters said tha t approval for the permit for Archer Daniels Midland's Decatur, Illinois project in the Mount Simon sandstone took over three years. Commenters said that only North Dakota has applied for primacy to issue Class VI permits in place of EPA, and no State has been approved, despite the pendency of North Dakota's application for the past 18 months. Commenters said that therefore, the EPA is the only permitting authority for these types of wells. Commenters said that this is a major concern for implementation of full

- scale CCS. Commenters said that EPA has not addressed how it will efficiently permit the hundreds of sequestration sites that will be necessary if CCS implementation is mandated to the existing coal

- fired electric generating fleet.

Commenters said tha t, in addition to the lengthy permitting process, the Global CCS Institute, an organization formed to support the development of CCS, says it takes up to 10 years to characterize a saline formation before large

- scale sequestration can occur. Commenters sai d that storage of CO2 in the context of wells already permitted for EOR has been shown to be feasible, and as research progresses, more areas are being shown to have capacity for EOR. Commenters said that however, opportunities for EOR today are constraine d by CO2 pipeline networks largely limited to certain oil

- producing regions in the Gulf, Southwest, and Great Plains.

Commenters said that, in addition to being unable to prove that CCS is reasonably reliable and reasonably efficient, the EPA cannot prove that it will not be "exorbitantly costly in an economic or environmental way." Commenters said that to provide perspective, the average price of electricity in PJM, the country's largest power market, ranges from $50

- 60/megawatt

- hour ("MWh"). Commenters sa id that according to Deputy Assistant Secretary of Energy for Clean Coal Julio Friedmann, the current cost of adding CCS to a coal

- fired generating unit translates to a 50

- 80% increase in the market price for power, thus accounting for a $30

- 40/MWh increas e.187 Commenters said that according to Assistant Secretary of Energy Chuck McConnell, "Affordable solutions may be decades away with the current level of funding and resultant R&D strategy .... Commenters said that, it is disingenuous to state that the techn ology is 'ready' and it is wrong to underfund to assure failure if the true goal is 'All of the Above."'

Commenters said that, there is high confidence that CCS technologies will work and that costs will decline substantially. But commenters stated that is far different from the legal threshold the EPA must clear to base an emissions standard on the technology.

Commenters stated, greenhouse gas emissions have not been regulated in the past, so existing power plants are not equipped with post

- combustion CO2 controls. Commenters said, CCS has not been adequately demonstrated at full scale on an existing power plant. Commenters said, there have been short term pilot tests, including one in West Virginia, where a small percentage (less than 2 percent) of the flu e gas was diverted and a fraction of the CO2 was captured and sequestered. Commenters said, however, this process has not been implemented on a commercial scale nor for extended periods. Commenters said, as EPA has verbally acknowledged, CCS is not a viabl e control option for existing sources. Commenters said, there are no adequately demonstrated add

- on controls for CO2.

Commenters stated that partial CCS technologies and technologies to improve the efficiency of the transmission system are unproven, insuff icient, and/or are not cost

- effective solutions for achieving the proposed state goals. Commenters added that CCS technologies have not been adequately demonstrated to be technically feasible or cost

- effective for fossil fuel

- fired generating units. With r espect to measures to improve the efficiency of the transmissions system, commenters said that technologies exist to improve performance, but significant concerns remain regarding the broad application, cost, and performance of such technologies. Commenter s said that the use of robust methodologies for sequestration of carbon in the landscape are increasingly important as growing demand for food and feed imposes more and more land use change from forestry to agriculture.

Commenters said that while CCS and I GCC technology was determined to be more expensive than other carbon reduction alternatives, the current cost of such technologies is not a guarantee that they will always be more expensive and does not consider that states may have additional,

non

- monetar y metrics for evaluating which programmatic and technological options they will deploy in order to achieve their target carbon emission rate reductions. Commenters said that defining eligible methods of reducing carbon emission rates as broadly as possible , while still affirming that verifiable carbon emission rate reductions are being achieved, will maintain the program's flexibility and will help states ensure that they have access to the lowest cost options available for achieving compliance with the EPA 's target carbon emission rates as well as other alternatives that states may deem to be in their interest to pursue. Commenters added that the EPA should allow states to use generation from new gas

- fired power plants in demonstrating compliance with a sta te's carbon emission rate target.

Comment 3: Commenters stated adding CCS technology to a biomass facility can lead to a net sequestration of carbon.188 Response 3: The EPA agrees that bioenergy with CCS

– often referred to as BECCS

- is a promising technology. However, biomass

- fired energy generation facilities (that do not co

- fire fossil fuels) are not subject to the final emission guidelines and therefore the EPA has not specifically addressed either the technical feasibility or the crediting of su ch facilities. See sections V.A of the final rule preamble of the CPP and Chapter 5 of the GHG Mitigation Measures TSD for CPP Final Rule for the EPA’s response to this comment.

The following are summaries of the specific public comments under this comment :
Commenters said that adding carbon capture and sequestration (CCS) technology to a biomass facility can lead to a net sequestration of carbon, and emissions from such facilities should be calculated in the same way as for a coal facility with CCS. Commen ters added that this method of calculation for a biomass facility with CCS potentially leads to negative net emissions from those facilities.

Comment 4: Commenters supported use of carbon capture mechanisms for compliance.

Response 4: The EPA has noted th at some specific sources may find CCS to be a preferable compliance option and that states are free to include CCS projects as approvable compliance options in state plans

. However, as detailed in sections V.A. of the final rule preamble and in Chapter 5 o f the GHG Mitigations Measures TSD, the EPA did not find CCS to be part of the BSER for these sources

. See sections V.A of the final rule preamble of the CPP and Chapter 5 of the GHG Mitigation Measures TSD for CPP Final Rule for the EPA’s response to this comment.
The following are summaries of the specific public comments under this comment:

Commenters urged EPA to include carbon capture mechanisms as a compliance tool, suggesting that a state can also authorize carbon capture and storage mechanisms to re duce emissions from existing coal plants. Commenters referenced the largest post combustion carbon capture project in the world, the Petra Nova Project in Texas, partially funded by DOE. Commenters stated this is projected to capture 90 percent of the carb on dioxide emissions from one of the plant's generators.

Comment 5: Commenters requested adjusting the GHG Rule with a conditional small municipal utility exemption for CWLP.

Response 5: The EPA has noted that some specific sources may find CCS to be a p referable compliance option and that states are free to include CCS projects as approvable compliance options in state plans

. However, as detailed in section V.A. of the final rule preamble and in Chapter 5 of the GHG Mitigations Measures TSD, the EPA did not find CCS to be part of the BSER for these sources. The EPA has specifically addressed CCS opportunities in the preamble to CPP F inal Rule and also how th ey may be included in approvable state plans. See sections V.A of the Final Rule preamble of the CPP and Chapter 5 of the GHG Mitigation Measures TSD for CPP Final Rule.189 The following are summaries of the specific public comments under this comment:

Comme nters stated CWLP is currently involved in the beginning phases of a study to determine the potential to install and operated membrane technology for the post

- combustion capture at Dallman Unit 4 and requested adjusting the GHG Rule with a conditional smal l municipal utility exemption for CWLP considering the limitations of CWLP being a very small, vertically integrated, municipal utility. Commenters stated the membrane is not a screen or filter, but rather

a non

- porous continuous defusing dense membrane to separate CO2 from nitrogen. Commenters stated that once defused, the nitrogen is rejected, while the CO2, once it permeates through the membrane, is captured and sent up the stack, and therefore must be pressurized. Commenters stated that participation in the study stretches CWLP's limited resources and already reduced staff, but demonstrates CWLP's commitment to technology

- forcing research toward reducing carbon emissions.

Comment 6: Commenters supported use of carbon capture mechanisms for compliance.

Response 6: The EPA has noted that some specific sources may find CCS to be a preferable compliance option and that states are free to include CCS projects as approvable compliance options in state plans

. However, as detailed in sections V.A. of the final rule preamble and in Chapter 5 of the GHG Mitigations Measures TSD, the EPA did not find CCS to be part of the BSER for these sources

. See sections V.A of the Final Rule preamble of the CPP and Chapter 5 of the GHG Mitigation Measures TSD for CPP Final Rule for EPA’s response to this comment.

The following are summaries of the specific public comments under this comment:

Commenters recommended EPA include carbon capture technologies in its proposal, allowing for their commercialization. Commenters submi tted diagrams and descriptions of a patented device for removing smoke and carbon dioxide from combustion emissions. Commenters stated the inventor claimed that the devices can control GHG emissions from existing power plants. Commenters stated under paten t, USP 7,631,506, CryoRain Inc. can process the entire air expelling from carbon fuel burning furnaces for heating and power generation in its Smoke Abatement line of equipment. Commenters stated rather than releasing the smoke, the technology can capture it and separate out the pollutants from mercury to the array of soots and carbon materials using liquid nitrogen sourced nitrogen gas to cool the smoke and do thermal separation.

Comment 7: Commenters suggested EPA recognize innovative post

- control techno logies such as direct air capture (DAC).

Response 7: The EPA has noted that some specific sources may find CCS to be a preferable compliance option and that states are free to include CCS projects as approvable compliance options in state plans

. However, a s detailed in sections V.A. of the final rule preamble and in Chapter 5 of the GHG Mitigations Measures TSD, the EPA did not find CCS to be part of the BSER for these sources

. In addition, the EPA does encourage the development and deployment190 of advanced a nd innovative technologies (in numerous agency programs) and has provided procedures to allow crediting for use of effective innovative technologies. See section V.A of the Final Rule preamble of the CPP and Chapter 5 of the GHG Mitigation Measures TSD for CPP Final Rule for EPA’s response to this comment.

The following are summaries of the specific public comments under this comment:

Commenters suggested EPA should recognize the potential emissions reductions from innovative technologies integrated into power plants and installed to control power plant carbon emissions directly at their source, such as Direct Air Capture. Commenters stated innovative emission reductions techniques such as Direct Air Capture are consistent with the approach employed by Bui lding Block One of the proposal, being tied directly to the reduction of on

- site emissions by regulated sources. Commenters stated its Global Thermostat technology is patent

- pending in over 100 countries, and uses low

- cost left over process heat as energy for the capture of CO2 from the atmosphere. Commenters stated it can be installed at a variety of new or legacy facilities that generate waste heat

- including power plants, cement smelters, refineries and other industrial operations. Commenters stated the technology removes CO2 directly from the air, rather than from a waste flue gas stream, and as a result, it can be located anywhere that makes sense from a sequestration or re

- utilization perspective where there is also waste process heat available. Comme nters also stated that the cost savings on the CO2 transportation side help to offset the differentially greater costs of removing CO2 from a less concentrated source than a power plant waste stream. Commenters also provided a legal justification for the i nclusion of direct air capture and other innovative technologies.

Commenters stated the proposed rule does not yet provide a clear regulatory structure that measures and credits the capture, sequestration, or beneficial use of GHGs already in the atmospher e. Commenters stated technologies

- including DAC technologies

- that reduce the inventory of GHGs are vitally important to reducing the global concentration of GHGs to levels that will forestall potentially catastrophic climate change. Commenters stated t here is no policy reason to favor reduction of GHG emissions from point sources over removal of GHGs from the ambient air, so EPA must consider the use of technologies that take advantage of the global presence of GHGs for removal, wherever that removal ma y occur

.

3.8. 2 Geologic storage

This section discusses the potential for geologic storage as a part of carbon capture and storage (CCS) as an emissions reduction method. The EPA is not identifying CCS at coal

- fired steam EGUs as part of the BSER, but it remains a control measure that some affected EGUs may be expected to implement.

Commenters have raised a number of issues related to the subsection which are organized by topics (comments) below. Responses are also provided for these topics. (Below the re sponse, comment summaries are noted.)191 Comment 1: Commenters stated geologic and other challenges make CCS unworkable.

Response 1: The EPA disagrees that CCS technologies are not workable. The components of CCS

– capture, compression, transportation, and s torage have been used for decades in a variety of industries

– including the power sector. Reference the preamble and supporting documents of the companion section 111(b) standards for GHG emissions from new, modified and reconstructed sources for detailed discussion of this, in particular sections V. M and N to the preamble to the final rule

. As noted there, not only are there ample sequestration opportunities in most areas of the country, and that EPA has promulgated plenary regulatory controls under the Underground I njection Control program to assure that sequestered carbon will not contaminate underground sources of drinking water and also have the practical effect of preventing releases of CO 2 to the atmosphere , but EPA has issued permits under the Class VI program

. The EPA further notes that CCS was not proposed to be

– or determined to be at final

– part of the BSER for existing fossil fuel

- fired EGUs. See sections V.A of the Final Rule preamble of the CPP and Chapter 5 of the GHG Mitigation Measur es TSD for CPP Final Rule for EPA’s response to this
comment.
The following are summaries of the specific public comments under this comment:

Commenters stated the geological, legal and technology challenges of CO2 storage are too pervasive for CCS to be a broadly applied solution during the relevant investment and compliance periods. Commenters stated it does not believe CCS would be available to states and sources as a compliance option. Commenters highly encouraged EPA to consult with DOE Fossil Energy O ffice and NETL experts and obtain their latest assessment of the concept, as well as their expertise and views on CCU.

Comment 2: Commenters stated issues with Wisconsin’s ability to use geologic sequestration.

Response 2: The EPA notes that CCS was not proposed to be

– or determined to be at final

– part of the BSER for existing fossil fuel

- fired EGUs. No state

– including Wisconsin

– will be required to include CCS technologies in their state plans. See sections V.A of the Final Rule preamble of the CPP and Chapter 5 of the GHG Mitigation Measures TSD for CPP Final Rule for EPA’s response to this comment.

The following are summaries of the specific public comments under this comment:

Commenters stated EPA has not qualified any sites in Wisconsin for geol ogical sequestration by injection. Commenters stated Wisconsin facilities that choose to adopt geological sequestration by injection must arrange to pipe

- line their future CO2 emissions out of state.

Comment 3: Commenters supported use of CCU as a compliance option.192 Response 3: The EPA has specifically addressed CCU opportunities in the final preamble and how they may be included in approvable state plans. See sections V.A of the Final Rule preamble of the CPP and Chapter 5 of the GHG Mitigation Mea sures TSD for CPP Final Rule for the EPA’s response to this comment. See also the next subsection of this document for EPA’s response to comment regarding enhanced oil recovery.

The following are summaries of the specific public comments under this comment:

Commenters stated EPA seems to assert that emissions reductions from CCU may only be achieved to the extent that captured CO2 is permanently stored or isolated from the atmosphere, however Commenters stated that this interpretation of permanence i s impermissibly narrow and at odds with EPA's definition of BSER under the proposed rule for existing sources, which does not require individual utilities to capture CO2 emissions, but instead allows states to use a variety of controls so long as the state wide CO2 target is achieved. Commenters stated that because carbon in CCU systems is recycled and returned to the economy, quantification and verification of CO2 reductions under CCU can be complex. Commenters stated EPA correctly points out in subsection VII(L)(3)(b) of its proposed New Source Performance Standard for New Power Plants ("Alternatives to Geologic Sequestration") that understanding the ultimate fate of the captured CO2 is essential to consideration of how CCU projects contribute to meeting th e performance standard. Commenters also stated EPA also correctly notes that the degree to which the method permanently isolates CO2 from the atmosphere is an appropriate measure by which to demonstrate reductions.

Commenters stated the appropriate measur e of permanence is whether the constellation of actions anywhere within the electric generation and distribution system results in permanent reductions in CO2 emissions to the atmosphere. Commenters stated this is the measure by which the four "building bl ocks" of the proposed BSER for existing sources are evaluated. Dispatching lower

- emitting and zero

- emitting energy sources or implementing end use energy efficiency does not permanently store or isolate emitted CO2 from the atmosphere, but these systems do result in permanent reductions in CO2 to the atmosphere. Commenters stated that likewise, CCU systems producing biofuels achieve the stack standard by avoiding emissions of CO2 through substitution for extraction and combustion of petroleum. Commenters st ated these systems permanently isolate CO2 from the atmosphere by ensuring petroleum

- based carbon remains sequestered underground. Commenters included in their comments a recent peer

- reviewed analysis supporting this conclusion.

Commenters stated that in contrast, use of captured CO2 for EOR, which is supported in the proposed rule, actually serves to increase extraction and subsequent combustion of fossil carbon. Commenters stated the proposed rule's explicit support of EOR without at least equal recognit ion of algae

- based CCU places technologies with the greatest potential for CO2 reduction at a distinct disadvantage, and EPA must remedy this outcome in the final rule.

. . Commenters stated that to assure compliance for CCU projects, EPA need only impos e appropriate monitoring and reporting requirements, as is required of CCS projects. Commenters stated this approach also appropriately constrains section 111 regulation to electric generating193 units. Commenters stated that Section 111 does not authorize EP A to regulate mobile sources, and it would therefore be inappropriate to attribute emissions from the combustion of CCU

derived biofuels in mobile sources to the EGU as suggested in the New Source proposal. Commenters stated such attribution of emissions w ould be unprecedented and impermissible under Section 111. Moreover, commenters stated, CO2 emissions and reductions would be double

- counted if CO2 emitted by mobile sources were attributed to an affected EGU in this way, and would compromise the GHG Repor ting Program by double

- counting CO2 emissions and reductions.

Commenters stated for the wide spectrum of products other than biofuels produced through CCU, the diversity of product lifespans, alternative substitution scenarios, and end

- of

- life options fur ther complicates accounting for lifecycle reductions in CO2 emissions, but significant work has been done in this area to establish accounting standards. Commenters stated that the Biotechnology Industry Organization has established industry Principles for the Accounting of Biogenic Carbon in Product Carbon Footprint (PCF) Standards, which are applicable to products derived from biological conversion of captured CO2. Commenters also stated the USDA BioPreferred Program established under the 2002 Farm Bill, has required lifecycle assessments of participating biobased products for more than a decade, and the program earlier this year released a comprehensive evaluation of the impact of biobased products on the economy and the environment. Commenters stated tha t the report cites a recent meta analysis of 44 lifecycle assessment studies of biobased products, which found that one metric ton of biobased materials saves, relative to conventional materials, 3

- 1 ton of CO2 equivalent in greenhouse gases. Commenters stated the USDA report also notes that several leading industry sustainability initiatives, including The Sustainability Consortium, the Sustainable Apparel Coalition, and the Bioplastic Feedstock Alliance, have employed lifecycle analysis to assess GHG re ductions from substitution of biobased materials. Commenters stated Coca

- Cola's use of PlantBottle packaging, for example, eliminated almost 30,000 metric tons of CO2 in its limited roll out of the new biobased material in 2010.

Commenters stated that whil e the lifecycle methodology for biobased products continues to evolve, it is clear that sufficient evidence of CO2 reductions exists now to justify inclusion of materials produced through biological conversion of captured CO2 under the proposed rule, along side biofuels. Commenters stated that clear guidance should be provided to states that use of carbon captured from regulated facilities for production of biofuels and other bio

- derived products is an approved mitigation strategy. Commenters strongly oppose d the assertion in the proposed rule for New Sources that "alternatives to geologic sequestration could not be used until the EPA finalizes a mechanism to demonstrate that a non

- CCS technology would result in permanent storage of CO2." Commenters stated th at EPA can and should make clear in both the New Source and Existing Source rules that CCU is an approved compliance option. Commenters stated clear articulation of monitoring and reporting requirements for such projects will ensure that the standard achie ves its objectives.194 3.8. 3 Enhanced oil recovery (EOR)

This section discusses the potential use of enhanced oil recovery as a part of carbon capture and storage (CCS) as an emissions reduction method. The EPA is not identifying CCS at coal

- fired steam EGU s as part of the BSER, but it remains a control measure that some affected EGUs may be expected to implement.

Commenters have raised a number of issues related to the subsection which are organized by topics (comments) below. Responses are also provided fo r these topics. (Below the response, comment summaries are noted.)

Comment 1: Commenters stated the EPA should adjust state

- specific building blocks to include CCS

- EOR.

Response 1: The EPA has noted that some specific sources may find CCS to be a preferable compliance option and that states are free to include CCS projects as approvable compliance options in state plans

. However, as detailed in sections V.A. of the final rule preamble and in Chapter 5 of the GHG Mitigation Measures TSD, the EPA did not find CCS to be part of the BSER for these sources

. See sections V.A of the Final Rule preamble of the CPP and Chapter 5 of the GHG Mitigation Measures TSD for CPP Final Rule for EPA’s response to this comment. In particular, the EPA noted that the exi sting fleet of fossil fuel

- fired EGUs vary considerably in their size, their location, etc. The EPA cannot predict which existing units can and cannot effectively integrate CCS or CCS

- EOR

. The following are summaries of the specific public comments under this comment:

Based on their own modeling efforts, commenters stated EPA should adjust relevant state

specific building blocks to include CCS

- EOR, especially if the Agency opts to finalize a rule based solely on building blocks 1 and 2. Commenters stated t he result of adding CCS

- EOR retrofits to the BSER building block 1 would be a target rate that reflects an incremental amount of CO2 reductions on the order of 85 million metric tons per year in 2030; this is a significant quantity of CO2. Commenters state d, in comparison, building blocks 3 and 4 together reduce CO2 by 262 million metric tons per year relative to the 2020 base case. Commenters stated the contribution by CCS could therefore be about 32 percent of the total contribution of building blocks 3 a nd together. Commenters stated if EPA finalizes its block 1 and 2 only approach to target setting, including CCS as part of building block 1 (referred to as Unit Specific Measures in these comments) helps maintain the stringency of the rule at a reasonable cost.

Comment 2: Commenters supported adoption of a regional CO2 EOR portfolio standard.

Response 2: See response to previous comment. In addition, the EPA has specifically addressed CCU opportunities in the final preamble and how they may be included in approvable state195 plans. See sections V.A of the Final Rule preamble of the CPP and Chapter 5 of the GHG Mitigation Measures TSD for CPP Final Rule for EPA’s response to this comment.

The following are summaries of the specific public comments under this c omment:

Commenters suggested that EPA adopt a regional CO2 EOR Portfolio Standard (CEPS) as the implementing policy instrument to exploit the flexibility of the proposed rule's option of pursuing a regional approach that would involve carbon trading while not only considering the four Building Blocks. Commenters stated the proposed CEPS would be enacted as a regional compact by a cluster of states having a large enough potential supply of anthropogenic CO2 to exploit much of the huge US potential for EOR th at can be exploited for new crude oil production using anthropogenic CO2. Commenters stated the CEPS could potentially enable market launch for promising CO2 capture technologies by helping support technology cost buy

down for costly early

- mover CCS projec ts. Commenters provided a lengthy discussion on the justification for the need to encourage CCS with captured CO2 used for EOR, as well as economic analyses on the impacts of the CEPS approach on a variety of technologies.

Comment 3: Commenters stated CC S

- EOR would increase CO2 emissions.

Response 3: The EPA did not propose nor is finalizing CCS or CCS

- EOR technologies are part of BSER in the CPP Final R ule. However, s tates may include such technologies in approval state plans. See sections V.A of the final rule preamble of the CPP and Chapter 5 of the GHG Mitigation Measures TSD for CPP Final Rule for EPA’s response to this comment. Comments maintaining that use of captured CO 2 for EOR results in a negative CO 2 balance, consider ed on a lifecycle basis, are mistaken

. The agency’s main response to this comment is in chapter 6 of the Response to Comment documents for the section 111 b standards of performance. As explained there, among other things, the most recent scholarly work in the field indicates that accurate assumptions about CO 2 utilization can result in significant increases in the volumes of CO 2 stored per barrel of oil recovery, and thus result in a significantly greater amounts of CO 2 avoided and sequestered associated w ith CO 2 - EOR. Also as explained under section 111 b Final Rule standards , recent scholarly work also notes that sources of CO 2 derived from coal as a source of CO 2 for EOR result in about 31% lower net CO 2 emissions per barrel of oil recovered compared to na tural

- source CO 2 - EOR. CO 2 - EOR has been successfully used for decades at many production fields throughout the United States, and is expected to continue for the foreseeable future. Furthermore, the decision to initiate or expand an EOR project is based on the economic viability of the specific project, and driven by broad market dynamics. In making a decision, EOR operators consider many cost components of the EOR project including engineering and design, new infrastructure development, electricity, and fue l costs in addition to the long term cost of purchasing CO 2 . These costs are balanced against the long

- term demand for oil and the price EOR owners or operators can receive for the additional oil produced throughout the lifetime of the project. EOR operato rs will obtain CO 2 from the most cost effective reliable source to make their projects viable. New sources of natural CO 2 are available and awaiting the right market conditions for development. Similarly , many anthropogenic sources other than EGUs such as g as plants are available to support the oil industry’s expansion of EOR as market196 conditions allow. Thus, the industry is not dependent solely on the CO 2 from EGUs to generate additional oil from EOR.

The following are summaries of the specific public comments under this comment:

Commenters stated that the major problem is that using carbon sequestration for EOR actually increases the amount of CO2 loading in the atmosphere as crude oil, that otherwise would be unavailable is extracted, refined and burn ed as fuel. Commenters further stated the energy used to effect capture and sequestration also must be balanced in this dubious equation since more CO2 must be released to the atmosphere to accommodate capture and transport of the CO2 to an EOR site.

Comme nters stated that any CCS power plants actually built will likely increase net emissions. Commenters stated that most CCS power plants (if any are built at all) will offset their costs by selling captured CO2 to EOR operations. Commenters stated that EPA, however, does not perform a life

- cycle analysis to net out the CO2 injected underground to increase oil production against the additional CO2 emitted when the recovered oil is combusted. Commenters referenced a DOE NETL analysis which indicated that nearly 20 billion metric tons of CO2 will need to be purchased by CO2

- EOR operators to recover the 67 billion barrels of economically recoverable oil. Commenters stated the analysis also indicated that of this, about 2 billion metric tons would be from natural s ources and currently operating natural gas processing plants, with the remainder of the CO2 demand (18 billion metric tons) would need to be provided by anthropogenic CO2 captured from coal

- fired power plants and other industrial sources. Commenters stated that according to EPA, combusting one barrel of oil emits, on average, 0.43 metric tons of CO2. Commenters stated that combining that conversion factor with NETL's analysis, injecting 20 billion metric tons of CO2 underground in EOR operations produces 67 billion gallons of oil that, when combusted, emits 28.81 billion metric tons of CO2. Commenters stated that even assuming no leakage from fugitive emissions, EOR produces 1.41 tons of CO2 emissions for every ton sequestered. Commenters stated the most eco nomical (or least uneconomical) CCS power plants

- those generating revenue from EOR operations

- would be counter

- productive as an emission

- control strategy. Commenters stated that a technology that, in commercial practice, increases rather than reduces e missions is, by definition, not a "best system of emission reductions." Commenters stated that consequently, EPA may not lawfully base a CO2 performance standard on partial CCS.

Comment 4: Commenters stated concerns regarding CO2 permanent storage in oil fields.

Response 4: The EPA did not propose nor is finalizing that CCS or CCS

- EOR technologies are part of BSER for the sources covered in this rule. States may include such technologies in approval state plans. See sections V.A of the final rule preamble of the CPP and Chapter 5 of the GHG Mitigation Measures TSD for CPP Final Rule for EPA’s response to this comment. The EPA has procedures in place to ensure safe and permanent storage of CO2 in geologic sequestra tion sites

– including in oil fields. The components of CCS

– capture, compression, transportation, and storage have been used for decades in a variety of industries

– including the power sector. See also the preamble and supporting documents of the compan ion section 111(b)1 97 standards for GHG emissions from new, modified and reconstructed sources for a detailed discussion as well as chapter 6

, of the Response to Comment document for section 111 b standards of performance.

The following are summaries of the specific public comments under this comment:

Commenters stated there is considerable uncertainty as to the fate of pressurized gases in geological media since the technology to map and monitor those gases is not fully developed. Commenters stated that curr ently, it should not be assumed that typical oil wells in typical oil fields are at all suitable for the permanent storage of CO2 or any other highly pressurized liquid or gaseous material. Commenters stated it should also be noted that CO2 used as EOR mig ht find future pathways to the surface as a result of new wells being drilled through the areas where it is claimed to be stored.

Comment 5: Commenters stated economic hurdles to EOR.

Response 5: The EPA did not propose nor is finalizing that CCS or CCS

- EOR technologies are part of BSER for the sources covered in this rule. States may include such technologies in approval state plans but the EPA does not require any existing sources to implement CCS or CCS

- EOR. See sections V.A of the Final Rule preamble of the CPP and Chapter 5 of the GHG Mitigation Measures TSD for CPP Final Rule for EPA’s response to this comment.

The following are summaries of the specific public comments under this comment:

Commenters stated EOR may be a viable option for using CO2 c aptured from coal EGUs, but geologic, infrastructure and economic factors can make what was initially feasible uneconomic. Commenters stated lithology, area, thickness, porosity and permeability can all affect a reservoir's viability. Commenters also state d higher oil prices and lower CO2 prices can also determine whether or not a reservoir will be economically viable for EOR. Commenters stated that instead of relying on revenue to offset the costs of CO2 capture, EGUs will be required to add significant co sts for transport and non

- EOR permanent storage. Commenters stated costs could range from $1 to $10 per ton for transport and $.5 to $10 per ton for permanent storage.

Comment 6: Commenters were concerned that the rule would discourage use of EOR.

Response 6: The EPA did not propose to ... nor is it finalizing that ... CCS or CCS

- EOR technologies are part of BSER for the sources covered in this rule. States may include such technologies in approval state plans. See sections V.A of the final rule preambl e of the CPP and Chapter 5 of the GHG Mitigation Measures TSD for CPP Final Rule for EPA’s response to this comment. The EPA does not agree that the rule would discourage use of EOR. The EPA has procedures in place to ensure safe and permanent storage of C O2 in geologic sequestration sites

– including in oil fields. The components of CCS

– capture, compression, transportation, and storage have been used for decades in a variety of industries

– including the power sector. The EPA also notes that reporting un der GHGRP subpart RR will not change the status of a UIC198 Class II well and that t he cost of compliance with subpart RR is not significant enough to offset the potential revenue for the EOR operator from the sale of produced oil for CCS projects that

are re liant on EOR. Reference the preamble and supporting documents of the companion section 111(b) standards for GHG emissions from new, modified and reconstructed sources for detailed discussion of this.

Comment 7: Commenters stated Denbury, one of their memb er companies, expressed concern that federal rules will "foreclose

- not encourage

- the use of CO2 captured by emissions sources in EOR operations." Commenters stated that Denbury identified that Subpart RR of the Greenhouse Gas Reporting Rules will allow an emitter to use EOR

- based storage "only where the offsite injector reports" the CO2 storage to EPA. Denbury states this would "result in an emitter trying to enforce an EPA rule upon an EOR operator now only subject to Subpart UU of the Greenhouse Gas R eporting Rule." Commenters stated this is a situation that would certainly lead to companies that use EOR avoiding the purchase of CO2 subject to those rules. Commenters stated concern about Subpart RR compliance, commingling of purchased and other CO2, an d rules governing storage could also lead to litigation.

Response 7: The EPA did not propose nor is finalizing that CCS or CCS

- EOR technologies are part of BSER for the sources covered in this rule. The rationale is described in sections V.A of the final rule preamble of the CPP and Chapter 5 of the GHG Mitigation Measures TSD for CPP Final Rule. The EPA disagrees with the commenter s ’ assertion that subpart RR requirements will result in EOR operators avoiding the purchase of CO 2 from EGUs. The cost of compliance with subpart RR is not significant enough to offset the potential revenue for the EOR operator from the sale of produced oil for CCS projects that are reliant on EOR. First, the costs associated with subpart RR are relati vely modest, especially in comparison with revenues from an EOR field. In the economic impact analysis for subpart RR, the EPA estimated that an EOR project with a Class II permit would incur a first year cost of up to $147,030 to develop an MRV plan, and an annual cost of $27,787 to maintain the plan; the EPA estimated annual reporting and recordkeeping costs at $13,262 per year. (Subpart RR costs are presented in 2008 US dollars.) Monitoring costs are estimated to range from $0.02 per metric ton (base cas e scenario) to approximately $2 per metric ton of CO 2 (high scenario). Using a range of scenarios (that included high end estimates), t hese s ubpart RR costs are approximately three to four percent of estimated revenues for an average EOR field, indicating that the costs can readily be absorbed. See 75 FR 75073. Furthermore, there is a demand for new CO 2 by EOR operators, even beyond current natural sources of CO 2 . For example, recent work by DOE has concluded that future development of EOR will need to rely on captured CO 2

. In addition, the Internal Revenue Code section 45Q provides a tax credit for CO 2 sequestration which is far greater than subpart RR costs. See preamble to section 111 b new source performance standards at V. N. as well as the detailed comment response in chapter 6 of the Response to Comment for the section 111 b standards of performan ce

Comment 8: Commenters recommended that new and retrofit CCS opportunities be included in building block 1.

Response 8: The EPA did not propose nor is finalizing that CCS or CCS

- EOR technologies are part of BSER for the sources covered in this rule. The rationale is described in sections V.A of199 the final rule preamble of the CPP and Chapter 5 of the GHG Mitigation Measures TSD for CPP Final Rule.

The following are summaries of the specific public comments under this comment:

Commenters stated CCS retrofit and new build opportunities are available in Indian country and should be included in building block 1. Commenters referenced an analysis performed by Charles River associates to model the likelihood that carbon capture and sequestration ("CCS")

r etrofits would be relied on as a compliance alternative, using EPA's assumptions but including more updated and more accurate assumptions about enhanced oil recovery ("EOR") storage availability and economics than EPA used in its modeling for the CPP. Comm enters stated the results of the analysis are that designated facilities in at least nine states are projected to use CCS with EOR storage as a compliance pathway.

Commenters stated CCS can result in near

- zero CO2 emissions from designated facilities and C CS

- EOR retrofit opportunities are available in Indian country. Commenters provided figures to demonstrate that CO2 pipelines to EOR fields either are currently or are proposed to run through Indian country or areas in close proximity to many Indian country jurisdictions. Commenters stated that physical proximity is one element potentially enabling CCS retrofits at designated facilities. Commenters also stated that areas of Indian country that do not have designated facilities also are within reasonable prox imity of CO2 pipelines and EOR projects, which could make new build CCS controlled power plants feasible. Commenters stated that such low

- carbon energy could support reduced utilization of the designated facilities in the region.

Comment 9: Commenters sta ted more guidance is needed on use of CCS.

Response 9: The commenters note that their specific concerns are outside the scope of this rulemaking. The EPA issued a memorandum from the Director of the Office of Ground Water and Drinking Water to regional UIC Program Directors in its regional offices, and summarized in section V.N. of the preamble of the companion section 111(b) standards for new, modified and reconstructed sources, reflecting the principle that geologic storage can continue to be permitted

un der the UIC Class II Program and the use of anthropogenic CO 2 in EOR operations does not necessitate a Class VI permit. See: “Key Principles in EPA’s Underground Injection Control Program Class VI Rule Related to Transition of Class II Enhanced Oil Recovery or Gas Recovery Wells to Class VI”, April 23, 2015, available at: http://water.epa.gov/type/groundwater/uic/class6/upload/class2eorclass6memo.pdf

The following are summaries of the specific public comments under this comment:

Commenters stated in order for CCS projects to be availab le as a compliance option as part of the EPA's programs to reduce CO2 emissions in the United States, it is essential that EPA's overarching regulatory framework operate efficiently and effectively. Commenters discussed various EPA rule development activit ies, suggesting the implementation of the Air and Water Office programs must be seamless for CCS to be an actionable emission reduction technology in the private sector. Commenters stated given EPA's decision to require partial CCS on new coal

fired and IG CC plants, and its recognition that such projects will be most economically viable200 where the captured CO2 is used for EOR, it is essential that the transition guidance provide a straightforward approach enabling continued injection of CO2 in the Class II w ells currently utilized by the oil industry

- including CO2 captured by new EGUs with partial CCS.

Commenters stated if EPA does not address this matter, companies will face significant challenges integrating carbon capture into new and existing power pla nts and industrial facilities. Commenters stated the ability to sell the captured CO2 to EOR operators provides an essential revenue stream for CCS projects and will enable the learnings that are so important to driving down the costs of CO2 capture. Comme nters stated that if EOR operators are unwilling to purchase this captured CO2 (or discount its value) because of concerns with EPA's implementation of the Class II

- Class VI transition, deployment of CCS projects on power plants in the US could become co st

- prohibitive for the foreseeable future, absent other incentives or sources of revenue.

Commenters stated, while recognizing that their specific comments on this issue are outside the scope of this rule

- making, they urged the EPA Office of Air and Radiat ion and the Office of Water to work together to facilitate the continued use of Class II wells for EOR with captured CO2 as failure to do so risks the future of CCS in the United States, and will make it much more difficult to reduce GHG emissions from the power sector. Specifically, commenters recommended that the Office of Water take the following steps in finalizing the draft transition guidance:

Revise the draft guidance to ensure that the roles and responsibilities of the Class II and Class VI director s are clearly described, and that the Class II director retains authority over the Class II program, including for such issues as permitting and compliance oversight.

Clarify that EOR projects are not at risk of transition as long as they are operating in compliance with their Class II permits and not creating an increased risk to USDWs.

Clarify that the source of the CO2 injected for EOR is not a determining factor for whether transition from Class II to Class VI is required.

Re

- emphasize EPA's prior state ments in the Class VI UIC rule that CO2 can be demonstrated to be permanently stored in an oil reservoir during the normal course of enhanced oil recovery activities in a Class II well. As EPA stated in the preamble to the final Class VI rule

- making:

Comme nters also stated that traditional ER projects are not impacted by this rulemaking and will continue operating under Class II permitting requirements. Commenters also stated EPA recognizes that there may be some CO2 trapped in the subsurface at these opera tions; however, if there is no increased risk to USDWs, then these operations would continue to be permitted under Class II.201 3.8. 4 Retrofit CCS: technical feasibility

This section discusses the technical feasibility of retrofit CCS as an emissions reducti on method. The EPA is not identifying CCS at coal

- fired steam EGUs as part of the BSER, but it remains a control measure that some affected EGUs may be expected to implement.

Commenters have raised a number of issues related to the subsection which are org anized by topics (comments) below. Responses are also provided for these topics. (Below the response, comment summaries are noted.)

Comment 1: Commenters agreed with the EPA that CCS is not adequately demonstrated.

Response 1: To clarify

- the EPA did not find that CCS is “not adequately demonstrated” for existing fossil fuel

- fired EGUs. The EPA noted that the existing fleet of fossil fuel

- fired EGUs vary greatly in size, location, available space, etc. and that integration of CCS technology at some loc ations would likely be very challenging and, thus, did not find CCS to be part of the BSER for these sources. However, the EPA further noted that some existing EGUs with available space and accommodating layouts may find CCS

– or maybe partial CCS

– to be an appealing compliance option

. This may be especially the case for sources that can take advantage of EOR opportunities

– much like the Petra Nova project at NRG’s WA Parish plant near Houston, TX. See sections V.A of the Final Rule preamble of the sectio n 111 (d) CPP Final Rule and Chapter 5 of the GHG Mitigation Measures TSD for CPP Final Rule for additional information. See also sections V.D. and E. of the preamble and supporting documents for the companion section section 111(b) Final Rule.

.
The follow ing are summaries of the specific public comments under this comment:

Commenters stated CCS is not "adequately demonstrated" as it has not been deployed commercially at any electric generating plant in the United States, with only a handful of such project s existing at the planning stages.

Commenters agreed with EPA's finding that CCS should not be considered as part of BSER for coal

- fired EGUs. Commenters stated CCS has not been adequately demonstrated. Commenters provided additional discussion in their co mments on Standards of Performance for Greenhouse Gas Emissions from New Stationary Sources: Electric Utility Generating Units: Proposed Rule, which were incorporated by reference.

Commenters agreed with EPA and compliments it for not proposing that CCS i s adequately demonstrated or commercially available at any scale for existing power plants. Commenters noted it filed extensive comments on this issue in response to the proposed NSPS for CO2 emissions from new power plants under Section section 111(b) of the CAA. Commenters stated that their comments in that proceeding provided a number of white papers and other information illustrating that CCS is not adequately demonstrated. Commenters stated if a power plant is located where CCS could be established , then those reductions should warrant compliance with the interim and 2030 deadlines in this Proposal. Commenters stated it is highly unlikely that a typical existing power plant located outside the oil and gas production regions of the U.S. could202 do this . Commenters stated if it is possible, such a plant should be deemed compliant with all interim and final obligations even if the power plant only achieved all its possible reductions at the time of the final deadline. Commenters stated between 2014 and 20 30, there is a possibility that new technology might emerge that could achieve a reduction in CO2 emissions from EGUs or that could result in CO2 destruction. Commenters stated if this were to happen, states should be allowed to revise their plans to refle ct the use of this new technology as compliance without having to complete the other measures in the plan.

Commenters agreed with EPA that partial CCS should not be considered BSER for existing coal

fired EGUs. Commenters referenced their comments on EPA' s January 2014 proposal for newly constructed sources, in which commenters explained in detail that CCS technology is not an adequately demonstrated system of emission reduction for newly constructed coal

- fired EGUs. Specifically, commenters explained that there are no such commercial

- scale, coal

- fired EGUs currently in existence and that EPA's reliance on heavily subsidized, pilot

- scale facilities and under construction, commercial

- scale EGUs was unwarranted. Commenters also identified a number of implemen tation challenges associated with CO2 transport and storage which were not adequately addressed by EPA. Commenters stated that the issues raised in those comments are equally relevant here. Commenters also stated, as EPA recognizes, design constraints, sit e

specific limitations, and a lack of proximity to potential geologic storage sites would make retrofitting existing sources with CCS technology more difficult. Commenters stated, thus, EPA was correct to conclude that partial CCS is not BSER and that any BSER analysis for coal

- fired EGUs should be limited to heat rate improvements.

Commenters stated CCS has not been adequately demonstrated and its implementation costs are unreasonable as this technology, on a commercially viable scale, has not yet been demonstrated on any operational coal

- fired unit. Commenters stated it illogical that CCS, partial or not, would even be identified by U.S. EPA as a viable approach as it is far to cost prohibitive and technically infeasible. Commenters stated limitations d ue to the physical location (including geological substrata) and layout and available space at a given location prevent CCS from being economically viable option. Commenters also stated that without substantial technological advances, inclusion of CCS as a n option is a short sighted unreasonable endeavor. Commenters referenced a DOE

- NETL funded research project through the Midwest Regional Carbon Sequestration Project which concluded despite numerous efforts to inject CO 2 into various stratigraphic layers o f the Appalachian Basin formation, injection pressures and flow rates were deemed insufficient for adequate CO 2 storage. Commenters also referenced a study by AEP and Batelle and the Mountaineer Power Plant during which AEP considered expanding the scope o f the project to capture approximately 20% of emitted CO2, however multiple major technical obstacles, insufficient cost

- recovery avenues, and substantial financial barriers were identified and the expansion project cancelled. Commenters also stated engine ering estimates for the expansion exceeded 1 billion dollars, and cost recovery avenues were very limited. Commenters also stated the expansion projected would also have required a large amount of physical space, approximately twice the size of the actual generating facility. Commenters also stated AEP encountered significant uncertainty, difficulty, and costs in procuring the necessary underground injection permits. Commenters stated that the study concluded that although technically feasible on a small va lidation

- scale, full commercial

- scale CCS was not feasible. Commenters stated that at present, and barring new technology, these results demonstrate that for power plants not specifically constructed, sited, and permitted with CO 2 capture and sequestration as the ultimate203 goal, CO 2 capture and sequestration is not a cost effective and reasonable approach to CO2 reduction. Commenters stated that it understand that the potential for CO 2 capture has been demonstrated on very small scales, but that the technolo gy is in its infancy and has not yet been demonstrated or made available on a commercial scale. Furthermore, Commenters stated the costs of CO 2 capture at even a limited scale are far beyond what they consider reasonable within the context of BSER. Comment ers stated the technology is at present not suited for consideration as a BSER and cannot be considered for "state flexibility."

Commenters stated it disagreed with EPA's finding that CCS has been adequately demonstrated, both from a technical and economi c perspective. Commenters stated that while this technology may have been prototyped on a small scale, it has not been demonstrated to be technically or economically viable on an industrial scale.

Commenters disputed EPA's contention that "partial CCS" has been "adequately demonstrated," is "technically feasible," and "can be implemented at costs that are not unreasonable." Commenters referenced comments submitted on EPA's proposed EGU GHG NSPS.

Commenters stated CCS should not be a component of BSER for C O2 emissions from existing fossil fuel

- fired EGUs since partial CCS has not been adequately demonstrated at full scale for existing units, is not technically feasible and cannot be implemented at costs that are reasonable.

Commenters stated EPA's current proposal to regulate new fossil fuel

- fired electric utility units under section section 111(b) of the Act is based on its finding that carbon capture and sequestration (CCS) has been adequately demonstrated. Commenters stated CCS has not been adequately de monstrated. Commenters stated far from having been demonstrated, there is uncertainty with respect to even the feasibility of the separation technology on a commercial scale as well as continued concerns about the availability of geologic formations for su bsequent sequestration. Commenters stated the legal implication is critical since EPA is barred from implementing an existing source rule under section 111 (d) without having successfully promulgated a new source standard under section 111 (b).

Commenters stated agreement with EPA's decision not to consider carbon sequestration to be BSER based on technical feasibility and high costs.

Commenters stated carbon capture should not be applied as a component of BSER for either new or existing fossil fuel

- fired electric generating units as it does not believe CCS is a proven technology. Commenters also referenced its similar comments on EPA's proposed section 111(b) rules.

Commenters stated support for the CPP conclusion that CCS is not currently commercially

av ailable and should not be considered to establish the BSER.

Commenters stated agreement with EPA that carbon capture and sequestration (CCS) should not be part of BSER. Commenters stated that the technical feasibility of CCS on a full scale coal

fired uni t has not been adequately demonstrated and the current costs are prohibitive. Commenters referenced their comments on EPA's proposed Standards of Performance for Greenhouse Gas Emissions from New Stationary Sources: Electric Utility Generating Units, which are incorporated by reference.204 Commenters stated support for CCS not being a component of the BSER for CO2 emissions from existing fossil fuel

- fired EGUs. Commenters stated externalities associated with CCS, which include EPA's assessment of heat rate im provements showing CO2 emission reductions were relatively limited, and therefore should preclude its use as a compliance option. Commenters referenced a NETL analysis that concluded retrofitting plants for carbon capture would increase freshwater withdraw al by 6 billion gallons per day and consumption by 4.3 billion gallons per day by 2030. Commenters also noted other health and economic costs associated with large

- scale coal extraction, stating that including of continued reliance on coal through CCS will simply shift one environmental problem with another. Commenters stated they

re

- affirm a July 2011 letter to then EPA Administrator Jackson, signed by scientists and environmental justice advocates outlining their concerns on CCS.

Commenters stated that th e arguments against CCS for retrofitting existing EGUs is even more compelling than that against new EGUs, given the following reasons: CCS has not been fully demonstrated; CCS produces large parasitic losses and requires additional energy, thereby offsett ing any heat rate improvements; Additional energy requirements equates to additional air pollutant emissions from CO2 separation, transportation, compression, and injection processes; Non

- air public health related environmental impacts resulting from parti al CCS were inadequately addressed; Lack of demonstration that the proposed rule secures a balanced solution; Absence of experience with at least one commercial scale coal

- fired CCS system; and, Sequestration of CO2 in large

- scale geologic storage areas is not an option for NC, particularly in areas where coal

- fired EGUs are located.

Commenters stated CCS technology is not ready for use, is not efficient, and is costly.

Commenters supported EPA's proposal to not require CCS, stating that the fact that the proposed performance standards do not anticipate any CCS is a reasonable indication that EPA is cognizant that CCS is not a currently available emissions control technology for EGUs, nor is it soon to be. Commenters stated EPA did not preclude CCS as a pro spective option for implementation, should the technology ever become demonstrably available.

Commenters stated that CCS should not be considered a technically viable option for facilities to install at this point as the technology is not commercially avai lable, is still in the testing phase, uses large amounts of energy to operate, and to this point has not proven to be a cost effective way of reducing CO2 emissions. Commenters also stated that CCS retrofit technologies require space around the boiler to b e installed, and many of Indiana's existing coal powered facilities currently lack sufficient space to install CCS.

Commenters stated the rule must subject any CCS plants to rigorous empirical verification, with no credit given to future promises or pledge s to implement or retrofit CCS to freely polluting plants. Commenters stated the feigned optimism of the power industry regarding CCS technology has dissipated year after year, with no breakthrough on the horizon. Commenters stated that because this techno logy remains on the drawing board, utilities are objecting that their technology for this does not constitute a valid objection to a Clean Air Act rule. Commenters stated that these companies have been promising CCS technology for decades, and have enjoyed equally prolonged federal research and development support concurrently. Commenters stated205 that unless and until some fundamental breakthrough in chemistry and material science, EPA need not indulge utility pledges of future science fiction.

Commenters s tated CCS decreases efficiency by increasing heat rate, and would thus directly undermine HRI goals. Additionally, commenters stated that according to the Center for Climate and Energy Solutions, CCS is prohibitively expensive and not widely commercially a vailable.

Commenters stated CCS is not commercially available and therefore it should not be considered to establish BSER.

Commenters stated notwithstanding the Administration's claim that CCS is "adequately demonstrated," serious questions remain about i ts technological and economic viability beyond unique applications. Commenters stated that at the same time, the EPA is poised to choke off the only economically viable CCS option, enhanced oil recovery, by putting in place regulations that would preclude its use as a carbon abatement option. Furthermore, commenters stated, the EPA has refused to recognize the use of other carbon utilization technologies for compliance purposes. Commenters stated there is no evidence that EPA's modeling has taken these

cons iderations into account.

Commenters stated that based on the current status of the TEC demonstration and a review of other ongoing CCS projects, CCS should not be considered BSER for existing units or for new units at this time. Commenters stated it is ap propriate to evaluate the feasibility of CCS in this context after the demonstration projects have been completed and the proper scale

- up has been achieved.

Commenters stated several technical and cost concerns with CCS. Commenters stated that aqueous min eral carbonation process, discussed in a Montana DEQ White Paper with respect to CO2 capture at the Colstrip Steam Electric Station, is energy intensive and not practical for field purposes. Commenters cited DOE that "the commercial success of CCUS (carbon capture utilization and storage) depends on developing more affordable technologies, since the cost of capturing CO2 from power plants is currently too high for wide

- scale implementation." Commenters also discussed the energy penalty associated with CCS, as well as transportation and storage cost concerns.

In comments submitted prior to the proposal in April 2014, and resubmitted following proposal, commenters offered the following as part of their to the question , " How should EPA set the performance stan dard for state plans," in EPA's " Considerations in the Design of a Program to Reduce Carbon Pollution from Existing Power Plants. "

With respect to CCS, commenters agreed with EPA's public statements affirming that CCS is not feasible for existing power pl ants and will not be considered for the best system of emission reduction (BSER). Commenters stated that the "demonstration" plants used by EPA to justify their selection of partial carbon capture as BSER in the proposed new source rule are not yet complet ed and operational, and none are traditional coal units. Commenters stated that CCS has not been deployed at commercial scale at any fossil

- fuel

- fired EGU and, therefore, has not been adequately demonstrated.206 Commenters stated agreement with EPA that CCS is not BSER for existing fossil fuel

- fired EGUs.

Commenters stated CCS should not be a component of the BSER for CO2 emissions from existing fossil fuel

- fired EGUs due to externalities associated with CCS. Commenters referenced EPA's assessment of heat ra te improvements showing CO2 emission reductions were relatively limited. Commenters also discussed an NETL study which concluded that retrofitting plants for carbon capture would increase freshwater withdrawal by 6 billion gallons per day and consumption b y 4.3 billion gallons per day by 2030. Commenters also stated other health and economic costs associated with large

- scale coal extraction including the direct and indirect effects of coal mining and mountain top removal require that a just energy transitio n to renewable and energy efficiency must not be impeded.

Commenters stated they are oppose to CCS and stated that CSS should not be a condition of compliance.

Comment 2: Commenters stated CCS retrofits are available and should be included under building block 1.

Response 2: In the proposal, the EPA noted that the existing fleet of fossil fuel

- fired EGUs vary greatly in size, location, available space, etc. and that integration of CCS technology at some locations would likely be very challenging and, thus , did not find CCS to be part of the BSER for these sources. However, the EPA further noted that some existing EGUs with available space and accommodating layouts may find CCS

– or maybe partial CCS

– to be an appealing compliance option

. This may be espec ially the case for sources that can take advantage of EOR opportunities

– much like the Petra Nova project at NRG’s WA Parish plant near Houston, TX. Therefore, the EPA agrees with the commenters that “CCS retrofits are available”; but, we do not believe t hat retrofits are a broadly applicable compliance option for the existing fleet of fossil fuel

- fired EGUs. See sections V.A of the final rule preamble of the CPP and Chapter 5 of the GHG Mitigation Measures TSD for section 111 (d) CPP Final Rule for additi onal information. See also the preamble sections V.D. and E. and supporting documents for the companion section 111(b) rulemaking.

The following are summaries of the specific public comments under this comment:

Commenters stated carbon capture and sequestration retrofits are available as unit specific measures under building block 1. Commenters referred to modeling performed by Charles River Associates which demonstrates that when more accurate and updated assump tions about CCS. Commenters stated CCS retrofit can result in near

- zero CO2 emissions from designated facilities. Commenters stated that the model assumes affected sources in 9 of those states are projected to apply CCS

- EOR as a compliance pathway and the results of this model would yield reduced CO2 emissions of nearly 85 million metric tons per year, or about 14 percent of the total annual reductions achieved nationwide in 2030 by the CPP, as compared to 2012 emissions. Commenters agreed with EPA in the d etermination that partial CCS was adequately demonstrated and a BSER for new fossil fuel

- fired steam EGUs and IGCC plants, and that CCS207 retrofits are demonstrated at existing EGUs, referencing Plant Barry, SaskPower's Boundary Dam, and W.A. Parish.

Commen ters noted that despite these facts, EPA also determines not to include any CCS or even partial capture (less than 90 percent capture) retrofits as an element of the BSER for existing power plants. Commenters referred to the EPA assertion that not all exis ting sources are located in close proximity to CO2 storage or pipelines, technical challenges with retrofit CCS such as the lack available land or space to host the capture equipment, and cost and non

- specific reliability concerns. Commenters stated these statements seemingly reflect the unrealistic assumption that including some CCS in the target setting equation in the rule would amount to a national mandate to apply CCS retrofits to all designating facilities, which of course is not the case for any of t he BSER technologies EPA has included in the target setting metric.

Commenters asserted that CCS retrofits are available over the period of this rule (to 2030) and should be included in building block 1 and used to evaluate state specific targets in the st ates identified as having EOR potential. Commenters stated including some retrofit CCS not only better reflects projected reality under their modeling (described infra) but also has potential to yield significant contributions to state targets and overall national CO2 reduction goals. Commenters provided a map which showed that the 17 states with EOR potential together account for about half of the total CO2 reductions EPA projects will occur under the CPP from 2012 to 2030.

Commenters suggested CCS can be grouped with other technologies that can reduce emissions directly at the designated facilities, under building block 1. Commenters stated that accepting for the sake of argument EPAs "broad applicability" criterion, as a whole this Unit Specific Measures approach to building block 1 would have broad applicability, just as building block 3 comprises a group of technologies not everywhere applicable including nuclear generation.

Comment 3: Commenters stated CCS should be the BSER for a subcategory of sourc es.
Response 3: In the proposal, the EPA noted that the existing fleet of fossil fuel

- fired EGUs vary greatly in size, location, available space, etc. and that integration of CCS technology at some locations would likely be very challenging and, thus, did not find CCS to be part of the BSER for these sources. However, the EPA further noted that some existing EGUs with available space and accommodating layouts may find CCS

– or maybe partial CCS

– to be an appealing compliance option

. This may be especially the case for sources that can take advantage of EOR opportunities

– much like the Petra Nova project at NRG’s WA Parish plant near Houston, TX. However, the EPA does not have adequate information to determine which of the many existing sources could integr ate CCS technology without insurmountable obstacles (such as limited space, integration with the existing steam cycle, pipeline access, etc.). We have noted that states are free to include CCS technology as a compliance option in approvable state plans. Se e sections V.A of the Final Rule preamble of the CPP and Chapter 5 of the GHG Mitigation Measures TSD for section 111 (d) CPP Final Rule for additional information. See also the preamble and supporting documents for the companion section section 111(b) rulemaking.208 The following are summaries of the public comments under this comment:

Commenters stated CCS should be included in BSER for a subcategory of plants where it is feasible and cost

- effective. Commenters stated that to constitute BSER, a system of emission reductions does not have to be met by every source "now in existence" in order to be considered adequately demonstrated. Commenters stated that instead of ruling out CCS altogether, EPA may create subcategories of existing coal

- fired power plants where CCS is appropriate. Commenters stated the agency has taken that very path in creating different categories for natural gas and coal

- fired power plants and applying different BSER to each. Commenters stated EPA should similarly determine the characte ristics of EGUs for which CCS is appropriate and adequately demonstrated (i.e., those facilities with sufficient physical footprint for capture and feasible access to pipelines or appropriate geographical formations for injection), and set CCS as BSER for that subcategory.

Comment 4: Commenters stated CO2 pollution control is currently feasible.

Response 4: The EPA agrees that CCS is technically feasible at all new EGUs as newly constructed facilities have the opportunity to site the project in a location with available storage or EOR availability and the opportunity to design the facility to ensure that space for the carbon capture equipment is available. However, as the EPA noted in the proposal, the existing fleet of fossil fuel

- fired EGUs vary greatly i n size, location, available space, etc. and that integration of CCS technology at some locations would likely be very challenging and, thus, the EPA did not find CCS to be part of the BSER for these sources. However, the EPA further noted that some existin g EGUs with available space and accommodating layouts may find CCS

– or maybe partial CCS

– to be an appealing compliance option

. This may be especially the case for sources that can take advantage of EOR opportunities

– much like the Petra Nova project at NRG’s WA Parish plant near Houston, TX. See sections V.A of the final rule preamble of the CPP and Chapter 5 of the GHG Mitigation Measures TSD for CPP Final Rule for additional information. See also the preamble and supporting documents for the companion section 111(b) rulemaking. See sections V.A of the Final Rule preamble of the CPP and Chapter 5 of the GHG Mitigation Measures TSD for CPP Final Rule for the EPA’s response to this comment.

The following are summaries of the specific public comments under this comment:

Commenters stated coal power plant CO2 pollution control is feasible and the first plants are being constructed at scale now. Commenters referenced Southern Company's 582

- megawatt Kemper plant and the NRG Energy announcement that they are mo ving forward on their 240

- megawatt coal plant with CO2 capture in Texas.

Comment 5: Commenters stated CCS is a demonstrated viable technology.

Response 5: See the response to the previous comments

. Also see sections V.A of the Final Rule preamble of the CPP and Chapter 5 of the GHG Mitigation Measures TSD for CPP Final Rule for the EPA’s response to this comment.209 The following are summaries of the specific public comments under this comment:

Commenters stated the Boundary Dam project, along with the SaskP ower Carbon Capture Testing Facility, will demonstrate that CCS is a viable technology and that it can be implemented at costs that are not unreasonable, while providing meaningful emission reductions. Commenters also stated that these projects, and learni ngs from them, will serve to promote further development and deployment of the technology.

Commenters stated that the economic value of the Boundary Dam project includes not only the reliable baseload electrical power for the Saskatchewan grid, but also th e material contribution to the local oil industry. Commenters stated EOR techniques substantially extend the viable production lives of oilfields, and provide important royalty revenues for the province. Commenters stated maintaining coal as a viable fuel for the Saskatchewan power industry provides fuel diversity benefits, a surety of supply, allows for more predictable energy prices; maintains the economic contribution of the coal industry, and provides community vitality. Commenters stated these industri al and mining activities also provide essential, well

- paying jobs, and other economic benefits to the province for the long

- term.
Commenters stated the Boundary Dam project has a number of important environmental benefits, including the capture of 90 perce nt of the CO2, 100 percent capture of the sulphur dioxide (SO2) emissions, and the reduction in particulate emissions is substantial. Commenters stated the SO2 is converted to sulphuric acid, and that sulphuric acid along the fly ash from the boiler, are s old as further by

- products. Commenters stated that Saskatchewan has a long history of CO2 storage experience, particularly in the Weyburn

- Midale oil fields. Commenters stated further knowledge will be gained at SaskPower's Carbon Storage and Research Centr e, and the Aquistore monitoring project it hosts

- which will provide important data and information for ongoing storage potential.

Comment 6: Commenters stated land constraints are not a major issue for all plants.

Response 6: The EPA noted in the propo sal, the existing fleet of fossil fuel

- fired EGUs vary greatly in size, location, available space, etc. and that integration of CCS technology at some locations would likely be very challenging and, thus, the EPA did not find CCS to be part of the BSER for these sources. Among the challenges is the availability of space

– however, that is not the only challenge and integration of commercially available CCS technology at existing EGUs across the country would be an enormously expensive endeavor. The EPA has noted, however, that some existing EGUs with available space and accommodating layouts may find CCS

– or maybe partial CCS

– to be an appealing compliance option. This may be especially the case for sources that can take advantage of EOR opportunities

– mu ch like the Petra Nova project at NRG’s WA Parish plant near Houston, TX. See sections V.A of the Final Rule preamble of the CPP and Chapter 5 of the GHG Mitigation Measures TSD for CPP Final Rule for additional information. See also the preamble and suppo rting documents for the companion section 111(b) rulemaking. See sections V.A of the final rule preamble of the CPP and Chapter 5 of the GHG Mitigation Measures TSD for CPP Final Rule for EPA’s response to this comment.210 The following are summaries of the s pecific public comments under this comment:

Commenters stated that contrary to EPA's assertions, land requirements for CCS are not a major issue for all plants. Commenters referenced a 2010 NETL study which evaluated the feasibility of retrofitting capture technology at existing power plants, using aerial and satellite images of various power plant sites, and concluded that no sites were totally infeasible for retrofit. Commenters also stated that for most plants, "there is the potential to have at least p artial retrofit, which means retrofitting only some of the generating units rather than the whole power plant." Commenters stated different capture technology options, especially oxy

- fuel, may require less space and increase partial CCS retrofit potential.

Comment 7: Commenters stated pipeline construction is no barrier to adoption of retrofit.

Response 7: The EPA agrees that the existing CO2 pipeline network can be expanded and, while the EPA does not dismiss the challenges with doing so, did not base its decision to not find CCS technology to be part of the BSER for these sources on those challenges.

The following are summaries of the specific public comments under this comment:

Commenters stated that during the period between now and the 2030 target date it is not unrealistic to expect that pipelines can be built linking existing power plants to geologica lly favorable storage sites. Commenters stated while it is certainly true that plants located closer to favorable geology are more likely to consider and install retrofit capture and sequester the captured CO2, the need for pipeline construction is not a u niversal barrier to any retrofits between now and 2030. Commenters stated that the challenge presented by the need for more CO2 pipelines to support the adoption of CCS retrofits is not conceptually very different from the challenge presented by the need t o expand natural gas pipeline infrastructure to serve existing plants for repowering, or increase reliance on existing natural gas plants resulting from redispatch under building block 2.

Comment 8: Commenters stated CCS need not cut into the existing ste am cycle of the power plant.

Response 8: The EPA agrees that a secondary source of steam or power can be used to supply the carbon capture system without the need to integrate with the existing source’s steam cycle

. However, the EPA did not base its findin g that CCS technology is not part of the BSER for these sources on any one particular challenge. Rather, the EPA found that, because the existing fleet of fossil fuel

- fired EGUs are so disparate, that it is difficult to apply CCS technology across the boar d as part of a nationwide “best system”. The EPA noted

– and we emphasize again here

– states may include CCS projects in state plants and some sources may find CCS to be a very feasible compliance option

– especially those that are ideally situated with a vailable space and near an EOR opportunity.

The following are summaries of the specific public comments under this comment:211 Commenters stated that adding CCS need not cut into the existing steam cycle of the power plant. Commenters referenced the plan for retrofitting the W. A. Parish plant in Texas demonstrates the added power needed for CCS can be met by building a small gas plant adjacent to the existing facility. Commenters stated this is not unlike the situation where small gas plants are needed for re liability purposes near some intermittent renewables.

Comment 9: Commenters stated CCS is infeasible in Nevada.

Response 9: The EPA notes that CCS was not proposed nor a part of the BSER for existing fossil fuel

- fired EGUs in the section 111 (d) CPP Final Rule . No state

– including Nevada

– will be required to include CCS technologies in their state plans. See sections V.A of the final rule preamble of the CPP and Chapter 5 of the GHG Mitigation Measures TSD for CPP Final Rule for EPA’s response to this co mment.
The following are summaries of the specific public comments under this comment:

Commenters stated CCS is not a feasible technology for Nevada. Commenters stated it does not support the inclusion of CCS as part of the BSER for the reasons set forth in their comments on the section 111(b) proposed rule, which are incorporated by referen ce. Commenters stated to summarize those comments, they believe it is untenable to include CCS as part of the BSER because (1) the technology is not adequately demonstrated, and (2) CCS by itself is too costly, and Nevada could not take advantage of CCS wi th enhanced oil recovery because of the small size of its oil fields and the temperature conditions of those fields. Commenters also stated Nevada's geology is not appropriate for CCS.

Comment 10: Commenters stated CCS is infeasible in North Carolina.

Res ponse 10: The EPA notes that CCS was not proposed to be

– or determined to be at final

– part of the BSER for existing fossil fuel

- fired EGUs. No state

– including North Carolina

– will be required to include CCS technologies in their state plans. See sect ions V.A of the final rule preamble of the CPP and Chapter 5 of the GHG Mitigation Measures TSD for CPP Final Rule for EPA’s response to this comment.

The following are summaries of the specific public comments under this comment:

Commenters stated North C arolina is one of sixteen states that lack geological formations that could serve as the basis for potential CO2 storage reservoirs. Commenters stated that in light of this critical limitation, EPA must not mandate the implementation of CO2 capture and sto rage for existing electric generating plants nor establish a standard based on CCS.212 Comment 11: Commenters provided a 29 page slideshow entitled "The Deployment of Clean Power Systems for Coal" presented by the ALSTOM company on May 16, 2007, which discus sed advanced CO2 Reduction and Capture Technologies

Response 11: The EPA notes that CCS was not proposed nor determined to bepart of the BSER for existing fossil fuel

- fired EGUs. No state will be required to include CCS technologies in their state plans. S ee sections V.A of the final rule preamble of the CPP and Chapter 5 of the GHG Mitigation Measures TSD for CPP Final Rule for EPA’s response to this comment.

Comment 12: Commenters recommended consideration of new technology for retrofitting.

Response 12: The EPA notes that CCS was not proposed or determined to be part of the BSER for CPP Final Rule for existing fossil fuel

- fired EGUs. No state will be required to include CCS technologies in their state plans. However, states are free to include CCS techno logy as compliance measures in state plans. The EPA has also indicated a procedure that will allow states to include new technologies

– such as those described in the submitted comments

– for approval under state plans. See sections V.A of the Final Rule p reamble of the CPP and Chapter 5 of the GHG Mitigation Measures TSD for CPP Final Rule.

The following are summaries of the specific public comments under this comment:

Commenters stated as currently designed, the Allam Cycle technology that NET Power is de veloping will be applied in new power plant settings, not as a retrofit CCS technology. Commenters stated there are configurations of the Allam Cycle that could enable retrofitting of EGUs that would result in major efficiency gains and emission reductions ; however, this version of the technology has a longer development and deployment timeline as compared to new

- builds. As such, commenters stated NET Power should not be considered as a retrofit opportunity in the current CPP.

3.8. 5 Retrofit CCS: reasonableness of cost

This section discusses the costs of the use of retrofit CCS as an emissions reduction method. The EPA is not identifying CCS at coal

- fired steam EGUs as part of the BSER, but it remains a control measure that some affected EGUs may b e expected to implement.

Commenters have raised a number of issues related to the subsection which are organized by topics (comments) below. Responses are also provided for these topics. (Below the response, comment summaries are noted.)

Comment 1: Commen ters stated the EPA exceeded its authority in determination of CCS.213 Response 1: This comment relates to the separate companion CPP rulemaking under section section 111(b) and is out of scope for the present rulemaking.

The following are summaries of the sp ecific public comments under this comment:

Commenters stated EPA exceeded its authority by basing its "adequately demonstrated" determination for CCS technologies entirely on projects that had received federal funding. Commenters stated the Energy Policy A ct of 2005 restricted the EPA's use of technologies that had received funding from certain federal programs in making its determination.

Comment 2: Commenters stated implementation of CCS may increase energy costs to

consumers.
Response 2: The EPA notes that CCS was not proposed to be

– or determined to be at final

– part of the BSER for existing fossil fuel

- fired EGUs. No state will be required to include CCS technologies in their state plans. However, states are free to include CCS technology as complia nce measures in state plans. The cost of including such technology should be a consideration in development of those state plans. See sections V.A of the final rule preamble of the CPP and Chapter 5 of the GHG Mitigation Measures TSD for CPP Final Rule.

Th e following are summaries of the specific public comments under this comment:

Commenters stated that the implementation of CCS in many existing EGU would very likely result in increased energy costs to consumers. Commenters suggested that by focusing on th ose EGUs that have chosen to study implementation of CCS (which be available to states and sources as a compliance option) might be a less onerous and costly approach to improve our understanding.

Comment 3: Commenters stated existing power plants have a capital advantage.

Response 3: The EPA noted in the proposal that some existing EGUs with available space and accommodating layouts may find CCS

– or maybe partial CCS

– to be an appealing compliance option

. This may be especially the case for sources that can take advantage of EOR opportunities

– much like the Petra Nova project at NRG’s WA Parish plant near Houston, TX. Those plants may indeed have a capital advantage over new plants. See sections V.A of the final rule preamble of the CPP and Chapter 5 of the GHG Mitigation Measures TSD for CPP Final Rule for additional information.

The following are summaries of the specific public comments under this comment:

Commenters stated existing plants actually have a capital advantage over new plants with respec t to CCS, because the investment to build an existing plant has already been made. Commenters stated the investment for CCS retrofits at an existing plant is just for costs of the control214 equipment, whereas in contrast, a new plant with CCS requires capita l for both the plant and the CCS equipment.

Comment 4: Commenters stated existing coal with CCS may have a cost advantage and therefore moved to the front of the dispatch order.

Response 4: As the EPA noted in the proposal, some existing EGUs with availab le space and accommodating layouts may find CCS

– or maybe partial CCS

– to be an appealing compliance option

. This may be especially the case for sources that can take advantage of EOR opportunities

– much like the Petra Nova project at NRG’s WA Parish pl ant near Houston, TX. It is quite possible that those plants

– due to the unique nature of the business plans

– may have lower costs and may therefore be higher in the dispatch order than other similar plants without CCS technology. See sections V.A of the final rule preamble of the CPP and Chapter 5 of the GHG Mitigation Measures TSD for CPP Final Rule for additional information.

The following are summaries of the specific public comments under this comment:

Commenters stated that depending on the price th e plant operator gets for selling the CO2 to an EOR operator, the dispatch costs for the plant with a CO2 capture retrofit can be less than the dispatch costs for the same existing plant prior to retrofit. Commenters stated that is because each hour of ope ration of the retrofit plant generates revenue from CO2 sales. Commenters also stated that with lower dispatch costs, the retrofit plant may operate more frequently, increasing electricity sales and increasing the economic value of the power plant asset. C ommenters provided an example on the dispatch costs advantage, which shows the electricity price needed in the market to dispatch a power

- generating unit. In the example provided by the commenters, a Texas coal plant receives $34 per short ton of CO2 sold to an EOR operator in the Permian Basin whereas the other units operate without CCS with the exception of a unit which must pay to dispose of its captured CO2 into a deep saline formation (not EOR). Commenters stated the illustration shows that EOR revenue s could vault existing coal with CCS to the front of the dispatch order, and allow such units to recoup the significant up

- front retrofit capital costs in the energy market.

Comment 5: Commenters provided comments on EPA’s IPM modeling of CCS for the CPP that predicted that no CCS would be built as a result of the CPP Final Rule

. Response 5: See section V.E of the final rule preamble of the CPP and Chapter 3 of the GHG Mitigation Measures TSD for CPP Final Rule for EPA’s response to this comment.

The following are summaries of the specific public comments under this comment:

"EPA's IPM modeling for the CPP predicted that no CCS would be built as a result of the rule. This was true even in states such as Texas where EOR is widely practiced, a retrofit p roject is already in construction, and the CO2 shadow price under the rule would be expected to be large given the substantial CO2 reductions represented by the state target. CCS is modeled in the CPP215 IPM runs using the assumptions found in EPA Base Case v 5.13. This base case uses capture costs developed for new and retrofit plants, and combines them with storage and transportation costs developed with GeoCAT, a spreadsheet model developed by ICF to support EPA's Safe Drinking Water Act Underground Injectio n Control (UIC) rulemaking in 2008. GeoCAT develops commercial scale costs for storage in four of several possible settings: saline reservoirs, depleted gas fields, depleted oil fields, and EOR. These settings are characterized by cost curves that reflect total sequestration capacity and annual storage volumes in each region or state, at various costs.

1. CATF commissioned modeling from Charles River Associates that corrected for outdated and incorrect EPA IPM assumptions.

CATF examined the CPP IPM runs an d the assumptions that drove EPA's IPM results. They found significant problems that they observed lead to a dramatic understating of the amount of CCS projected to be built as a result of the CPP. A central problem is that GeoCAT has not been significantl y updated since 2008. The GeoCAT cost curves for EOR price and supply thus are based on outdated assumptions, including:

• Oil prices are assumed to be $56 per barrel in GeoCAT. This low oil price significantly lowers the model's price paid for CO2.

• CO2 sent to EOR fields is assumed to meet Safe Drinking Water Act UIC program Class VI injection well standards, not UIC Class II with Clean Air Act subpart RR monitoring and reporting. As a result, EOR costs are overstated and the price field owners paid for CO2 is understated in EPA's modeling.

• Since 2008, 'next generation' EOR practices have been developed that greatly expand the EOR sequestration capacity in the United States. While GeoCAT assumes about 13 Gigatons of CO2 EOR capacity, today's estimates are clo ser to twice that value.

• Transportation costs included in GeoCAT are based on simplifying regional assumptions. But their observation is that at least for some states (Texas and Oklahoma, e.g.) these simplifications greatly overstate the costs of bringing CO2 from power plants to EOR operations.

The maximum price paid for CO2 in EOR operations anywhere in the U.S. under GeoCAT's assumptions is $14.52 per short ton. But CO2 prices in the Permian Basin in 2014 were typically around $35 per short ton, by cont rast, and elsewhere in the U.S.; prices paid for CO2 to be used in EOR began at $20 per short ton. Furthermore, the transportation costs assumed by GeoCAT likely overstate the pipeline costs by several dollars per short ton, at least in regions with existi ng EOR. Therefore the net revenue received for sale of CO2 to the EOR operator by the power plant owner will be underestimated by EPA, because both the assumed value of the CO2 in EOR is too low, and the assumed transportation costs are too high.

EPA's CO 2 capture scenarios

- that is, the 'world' modeled in the CPP IPM runs

- also are limited. For example, CCS can only be retrofit on a coal unit; IPM does not allow CCS on any216 new or retrofit existing natural gas units. And coal unit retrofits are limited t o a single size (400 MW or greater) and to 90 percent CO2 capture only. Partial capture (for example, capture on only one unit of a multi

- unit plant, leading to, say 50 percent capture was not an available option in the model. New build CCS also is limited just to 90 percent capture, and applied only on IGCC plants: IPM does not include even the partial capture option as EPA proposed it in the Agency's new source performance standards for this industry under Clean Air Act section section 111(b) . Taken together, these limited scenarios are likely to make CO2 capture retrofits appear both much less likely, and much more expensive in the IPM model runs used to support CPP than if more expansive CO2 capture scenarios are considered. A wider set of scenarios properly should include consideration of partial and full capture, on both new and existing natural gas and coal units (both pulverized coal and IGCC), and sensitivities concerning how unit size, coal types and existing plant heat rates impact capture cos ts.
To address these issues, CATF developed its own model runs of the CPP rule. They replicated the CPP policy case, and then made changes only to the CCS assumptions used by EPA, in order to examine the impacts on CCS retrofits and new builds. CATF retain ed Charles River Associates (CRA) to evaluate the economic competitiveness of CCS as a CPP compliance option for 'CCS

- Ready' states where CO2 captured at power plants can be used for EOR.

CRA evaluated CCS as a compliance option in three target states: Tex as, Oklahoma, and Mississippi. These three states were chosen due to the kinds of EOR activities currently underway there, which are representative of EOR activity taking place elsewhere in the country. Also, these states are in close physical proximity to one another making modeling simpler, and by focusing on three states, CATF could look more closely at transportation issues and EOR CO2 price effects.

CRA configured the fundamental power market model North American Electricity and Environmental Model (NE EM) to reflect, to the extent possible, the modeling assumptions used by the EPA in its CPP modeling. The resulting 'EPA Policy Case' scenario provided a benchmark against which the results of subsequent assumption changes can be measured."

:

Conclusions a nd recommendations:

i. CCS is a significant compliance pathway in two of the three EOR states studied in detail by CATF.

Another way to evaluate the significance of the CCS

- EOR reductions modeled by CATF is to compare them to the reductions EPA estimated i n assessing the CO2 reduction potentials of its various building blocks. For example, EPA developed a simplified cost estimate for its building block 1 (HRI), which it modeled would achieve 97 million metric tons of CO2 reductions by 2030

. By comparison, t he total CO2 reductions modeled to be achieved by 2030 using CCS

- EOR in the scenarios modeled by CATF range between 25 and 100 million metric tons. The World 1 scenario incorporates what CATF believes are the best estimates for both EOR price, supply and C O2 transportation and best estimates of retrofit costs. Therefore the most likely result is 85217 million metric tons sequestered under the World 1 scenario

- an amount comparable with the CO2 reductions EPA projects will be achieved by heat rate improvements

.
The modeled CCS

- EOR CO2 emissions reductions moreover are economically reasonable. As described earlier in the analysis and results section, the reductions in World 1 are achieved at less cost than in the EPA Base Case. The CATF World I run showed that there are small but meaningful decreases in total system costs in the RTOs encompassing Texas and Oklahoma, where CCS is retrofit. In present value (2014

- 2054) terms, total system costs in SPP_S decrease by $5.1 billion, or 2.4 percent, and in the ERCOT, s ystem costs decrease by $2.4 billion, or 0.5 percent. "

Comment 6: CCS is not economically feasible.

Response 6: The EPA agrees that CCS would be challenging

– both technically and economically

– for many existing fossil fuel

- fired EGUs. However, as the E PA noted in the proposal, some existing EGUs with available space and accommodating layouts may find CCS

– or maybe partial CCS

– to be an appealing compliance option

. This may be especially the case for sources that can take advantage of EOR opportunities

– much like the Petra Nova project at NRG’s WA Parish plant near Houston, TX. See sections V.A of the final rule preamble of the CPP and Chapter 5 of the GHG Mitigation Measures TSD for CPP Final Rule for additional information.

The following are summarie s of the specific public comments under this comment:

Commenters agreed with the EPA decision to rule out carbon capture and storage (CCS) from the determination of the BSER for existing sources. Commenters presented in their comments on the proposed NSPS a detailed discussion of why CCS is not economically feasible, therefore, commenters continued to maintain that CCS is not currently demonstrated for the determination of BSER for both new and existing EGUs..

Commenters stated that CCS at this time faces a n economic barrier and is not practical to apply to most EGUs regulated by the rule. Commenters referenced a projection of costs for CCS was completed as a Phase I DOE Project when Wolverine Power Cooperative applied for and received a coal

- fired EGU air p ermit in Michigan. Commenters stated the capital costs for transportation of the carbon dioxide 52 miles to an existing enhanced oil recovery (EOR) site were in the range of $130 million (M) to $170M with annual operating costs of $4M to $5M. Commenters al so stated the potential annual EOR revenue is $20M to $40M, and while the potential revenue is adequate to cover the cost of transportation and oil recovery, it does not provide revenue adequate to cover the capital costs of carbon capture at the power pla nt, which is in the range of $210M. Commenters stated these costs are for CCS of only 15 percent of the CO2 from a 300 MW unit and do not cover the cost of 100 percent CCS of the plant emissions.

Commenters stated given that the DOE CCS research will not be complete until 2020, financing will not be available to build a coal

- fired power plant without government subsidy for an unproven coal technology. Commenters stated the Administration's budget for funding of new CCS projects in the future is unlikely or uncertain at best. Additionally, commenters stated,218 retrofitting existing units is always more costly than new construction, and pipelines would have to be permitted and constructed, further adding to the cost, complexity, and time constraints of such app roaches.

Commenters stated that even with subsidies, a utility building a coal CCS power plant exposes its investors to considerable financial risk. Commenters provided additional information on the Kemper County project and associated cost overruns. Comme nters stated that any future CCS plants, particularly if constructed without subsidies, would likely impose greater costs on ratepayers, as well.

Commenters stated that when setting a performance standard, EPA is to take "cost" into account. Commenters sta ted that the D.C. Circuit Court of Appeals has interpreted that requirement to mean that a performance standard may not be "exorbitantly" expensive (Essex Chemical Corp. v. Ruckelshaus, 486 F. 2d 427 at 433, D.C. Cir. 1973). Commenters stated that EPA clai ms "partial" CCS is comparable in cost to other non

- NGCC options. Commenters stated however, the utility

- scale partial CCS plant nearest to completion is the Kemper Project in Mississippi and the facility's cost has increased from an initial estimate of $2 .2 billion to $6.1 billion. Commenters stated that based on Energy Information Administration (EIA) data, the Kemper Project is 88% to 107% more expensive than advanced pulverized coal plants and 496% more expensive than advanced NGCC power plants.

Commenters stated there is insufficient supporting information on costs for partial CCS to be considered BSER for reconstructed utility boilers and IGCC units. Commenters stated utility boilers are numerous and diverse in size and configuration, and the EP A does not have sufficient information on the range of specific configurations that would be necessary to estimate the cost of partial CCS, on either a source

- specific or industry

- wide basis. Commenters stated the cost of a retrofit would depend on many si te

- specific details, including the space available for the capture equipment, and the EPA lacks information on such details for a significant portion of the industry. Commenters stated carbon storage technology remains under development and has yet to prog ress to the stage where it can be considered for purposes of identifying BSER. Commenters also stated it is unknown whether injecting large volumes of CO2 at high pressure below ground may cause seismic events under some circumstances or result in effectiv e containment. Commenters also stated many EGUs are not located near sites that are geologically or otherwise suitable for carbon sequestration.

Comment 7: Commenters opposed CCS requirements for Pennsylvania.

Response 7: The EPA notes that CCS was not pr oposed n or determined to be part of the BSER for CPP Final Rule for existing fossil fuel

- fired EGUs. No state

– including Pennsylvania

– will be required to include CCS technologies in their state plans. See sections V.A of the final rule preamble of the C PP and Chapter 5 of the GHG Mitigation Measures TSD for CPP Final Rule for EPA’s response to this comment.

The following are summaries of the specific public comments under this comment:219 Commenters stated opposition to the inclusion of CCS requirements for any natural gas

- fired power plant in Pennsylvania's state implementation plan, given the significant costs associated with such technology. Commenters stated CCS is a prohibitively expensive emissions control, one that adds, according to the Pennsylvania Department of Environmental Protection (DEP), an additional 80% to the cost of building a power plant. Commenters also stated EPA's rule also flirts with requiring CCS for natural gas plants, noting that the agency "invite[s] comment on whether incremental emissions reductions from new NGCC units that outperform performance standards for such units under CAA section 111 (b) based on the use of CCS should be allowed as a compliance option to help meet the emission performance level required under a CAA secti on 111(d) state plan."

Comment 8: Proposed standard not achievable.

Response 8: This comment seems to be in response to the companion rulemaking under section 111(b) and is, thus, out of scope for the present rulemaking under 111 (d) . Commenters are encouraged to examine the preamble and supporting documentation for the section 111(b) rulemaking for responses to similar comments.

The following are summaries of the specific public comments under this comment:

Commenters stated EPA clai ms partial CCS costs "are comparable to costs of other non

- NGCC technologies," whether or not opportunities exist to sell the captured CO2 to oil companies for use in enhanced oil recovery (EOR) operations. Commenters stated that assessment conflicts with the track record of the Kemper Project. Commenters also stated that since no utility

- scale CCS power plants are currently being built without subsidies, EOR

- related revenues are likely essential to the commercial viability of non

- subsidized plants.

Referen cing EPA statements, commenters stated it is reasonable to assume that few if any CCS plants financed solely with private capital will be built in states where the geology is unsuitable for EOR operations. Commenters stated that CAA section 111(a) requires that performance standards be "achievable." Commenters stated that the D.C. Circuit Court of Appeals has interpreted the term to mean achievable for the industry as a whole (National Lime Association V. EPA, 627 F. 2d 416 at 443); however EPA identifies o nly 12 states with significant EOR operations. Commenters stated that coal power plants not located in relative proximity to oil fields would not have a market for their captured CO2, and hence, the proposed standard is not achievable.

Comment 9: Comment ers stated the long

- term efficacy of carbon capture and storage is
unproven.
Response 9 : The EPA notes that CCS was not proposed to be

– or determined to be at final

– part of the BSER for existing fossil fuel

- fired EGUs. No state will be required to inclu de CCS technologies in their state plans. See sections V.A of the final rule preamble of the CPP and Chapter 5 of the GHG Mitigation Measures TSD for CPP Final Rule for EPA’s response to this220 comment. Commenters are also encouraged to examine the preamble and supporting documentation (including the RTC) for the companion section 111(b) rulemaking for new, modified, and reconstructed sources for detailed discussion on this topic and responses to similar
comments.
The following are summaries of the specific public comments under this comment:

Commenters stated they were pleased to see that there is not a strong emphasis in this plan on carbon

- capture and storage (or enhanced oil recovery for that matter), since EPA has identified the high

- cost of retrofitting existing plants for this purpose. Commenters stated the long

- term efficacy of carbon capture and storage is unproven.

Comment 10: Commenters stated R&D funding for CCS should be increased.

Response 10: The EPA has, at several times, noted the importance of R&D in the further development and deployment of advanced technologies

– including CCS

. However, the primary sponsor of federally funded R&D for CCS is the U.S. Department of Energy (DOE).

The following are summaries of the specific public comments unde r this comment:

Commenters called for increased R&D funding for CCS/CCUS technology to ensure that there are lower cost technologies for different power plants and industrial processes and for different CO2 storage or reuse applications to have a chance at effectively deploying CCS/CCUS in the future.

Comment 11: Commenters expressed support for CCS.

Response 11: The EPA believes that CCS is a very promising technology for many existing fossil fuel

- fired EGUs. As the EPA noted in the proposal, some existi ng EGUs with available space and accommodating layouts may find CCS

– or maybe partial CCS

– to be an appealing compliance option

. This may be especially the case for sources that can take advantage of EOR opportunities

– much like the Petra Nova project a t NRG’s WA Parish plant near Houston, TX. See sections V.A of the final rule preamble of the CPP and Chapter 5 of the GHG Mitigation Measures TSD for CPP Final Rule for additional information.

The following are summaries of the specific public comments und er this comment:

Commenters stated EPA's Existing Source proposal can offer a mechanism for rewarding the low emission benefits offered by CCS and lead to a leveling of the commercial playing field for "climate friendly" sources of electricity. Commenters supported the need for predictable, easily implemented, and clear regulatory frameworks for both capture and sequestration. Commenters also believed that a flexible, technology neutral approach will reveal cost

- effective opportunities for CCS projects to c ontribute to the substantial carbon dioxide emissions reductions required of the US power sector in the coming decades.221 3.8. 6 Retrofit CCS: emission reductions and promotion of advanced technology

This section discusses the possible emission reductions and potential promotion of advanced technology as a part of carbon capture and storage (CCS) as an emissions reduction method. The EPA is not identifying CCS at coal

- fired steam EGUs as part of the BSER, but it remains a control measure that some affected EGUs may be expected to implement.

Commenters have raised a number of issues related to the subsection which are organized by topics (comments) below. Responses are also provided for these topics. (Below the response, comment summaries are noted.)

Comment 1: Commenters stated there is a need for CCS incentives and policies supportive of CCS.

Response 1: The EPA believes that CCS is a very promising technology for many existing fossil fuel

- fired EGUs. As the EPA noted in the proposal, some existing EGUs wit h available space and accommodating layouts may find CCS

– or maybe partial CCS

– to be an appealing compliance option

. This may be especially the case for sources that can take advantage of EOR opportunities

– much like the Petra Nova project at NRG’s WA Parish plant near Houston, TX. See sections V.A of the Final Rule preamble of the CPP and Chapter 5 of the GHG Mitigation Measures TSD for CPP Final Rule for additional information.

The following are summaries of the specific public comments under this com ment:

Commenters stated that the U.S. should lead the world in the development of CCS technology, however, the proposed rule does not provide any incentives for CCS technology deployment. Commenters stated that the U.S. is falling behind in CCS development and deployment due to inadequate federal assistance. Commenters noted that the IPCC has recognized that deployment of CCS technology on all fossil

- based energy systems is essential if the world is to meet future targets for the stabilization of atmospheri c GHG concentrations. Commenters stated EPA should encourage the option to deploy CCS at existing power plants through an incentive mechanism, such as encouraging states to create set

- asides, bonus allowances, or comparable programs for the benefit of firm s that invest in partial or full CCS. Commenters suggested that similar incentives to those used for the production of electric and hybrid vehicles, such as emissions exemptions, could be established within the rule to encourage the deployment of CCS techn ologies.

Commenters stated EPA should provide incentives for greater at

- the

- unit reductions such as those available from CCS. Commenters stated CCS technology is key to the long

- term viability of the coal industry, and could provide numerous ancillary bene fits, including EOR. Commenters stated that although they did not believe CCS can be considered BSER because it is neither adequately demonstrated nor reasonable in light of the high cost of reducing emissions through existing CCS technologies, they urged EPA to include provisions in the final rule to encourage222 EGUs to invest in this technology. For example, commenters stated, EPA could encourage states
to create set

- asides, bonus allowances, or comparable programs for the benefit of firms that invest in pa rtial or full CCS. Commenters stated EPA employed similar incentive mechanisms to encourage the production of electric and hybrid vehicles in its Tier 3 light

- duty vehicle standards for 2017

- 2025. Commenters stated EPA should also consider giving states th at identify CCS as one component of their implementation plan additional time to implement the expected emission reductions that this technology will provide.

Commenters stated that the rule does not provide any incentives for CCS technology deployment. Co mmenters stated the U.S. appears to be falling behind in CCS RR&D due to inadequate federal assistance. Commenters stated the option to deploy CCS at existing power plants should be encouraged through appropriate incentive mechanisms, such as set

- asides or bonus allowance programs for the benefit of firms that invest in partial or full CCS.

Commenters stated that state projects and policies to support carbon capture and sequestration for coal plants can play an important role in achieving reductions from th e existing fossil fleet. Commenters provided the example that Illinois has supported the development of clean coal projects through the FutureGen project in conjunction with the U.S. Department of Energy. Commenters stated that Illinois also passed the Cle an Coal Portfolio Standard Law, which requires new coal

- fired power plants to capture and store more than half of the carbon emissions that the facility would otherwise emit.

Commenters stated a need for increased funding from the government to further dev elop CCS technologies. Commenters stated the promotion and funding of CCS technology development is essential to continuing the progress of facilities and recommended DOE should receive an increased appropriation to provide funding to further develop carbo n capture and storage technology essential to ensuring that coal remains a vital and competitive asset in the United States' energy portfolio.

Commenters stated EPA should fully commit to CCS technologies and workforce retraining. Commenters suggested EPA connect meaningful federal investment in CCS technology, as well as beneficial reuse of carbon, to the implementation of the requirements on coal

- fired generation. Commenters recommended EPA engage all other agencies and all stakeholders to construct a

rea listic pipeline of technology and people to achieve environmental goals and build a growing
economy.
Commenters stated this Administration has dropped the ball when it comes to making the necessary investments to bring CCS technology to market, and these r evelations threaten to derail the commercialization of CCS altogether. Commenters stated the DOE is only investing a fraction of what it spends on research and development in renewable energy and energy efficiency on CCS.

Commenters stated the need for po licies that boost public private sector coordination to finish the first CCS plants and develop the second generation. Commenters stated R&D in coal technologies has provided great value to tax payers, with a return of $13 for every $1 of federal funding.223 Commenters stated that the rule should specifically encourage the states to embrace policies that will support the modernization of existing power generation infrastructure so critical to many of our states' economies. Commenters stated this should includ e a recognition that coal will continue to play an important role in meeting our essential power needs. Commenters stated technology such as carbon capture and sequestration are essential not only to protect the thousands of family

- supporting jobs associat ed with coal

- fired generation, but also as an essential component of any workable plan to address climate change.

Comment 2: Commenters state modeling indicates benefits using CCS

- EOR retrofits.

Response 2: In the proposal, the EPA noted that the existing fleet of fossil fuel

- fired EGUs vary greatly in size, location, available space, etc. and that integration of CCS technology at some locations would likely be very challenging and, thus, did not find CCS to be part of the BSER for these sources. However, the EPA further noted that some existing EGUs with available space and accommodating layouts may find CCS

– or maybe partial CCS

– to be an appealing compliance option

. This may be especially the case for sources that can take advantage of EOR opportunitie s

– much like the Petra Nova project at NRG’s WA Parish plant near Houston, TX. See section V.A of the Final Rule preamble of the CPP and Chapters 3 and 5 of the GHG Mitigation Measures TSD for CPP Final Rule for additional information related to this comment.
The following are summaries of the specific public comments under this comment:

Commenters stated CCS is a significant compliance pathway in two of the three EOR states studied in detail by CATF. Commenters discussed the results of modeling effort s to assess CCS. Commenters concluded:

"CATF's modeling predicts significant CO2 tonnage reductions will be achieved using CCS

- EOR retrofits on affected units in Texas, and this accounts for 25

- 65 percent of the total CO2 reductions that must be achieved in 2030 as a result of the CPP Texas CO2 emission targets. For Oklahoma, CATF's modeling predicts CO2 reductions using CCS

- EOR retrofits of between 21and 92 percent of the 2030 CPP targets, depending on the scenario modeled. In Mississippi, the only CCS s hown in the CATF modeling is Kemper, which is considered an existing source under the rule.

The emissions reductions that their modeling shows can be achieved by CCS

EOR retrofits are significant when compared with the sum of the CPP's state emissions redu ctions targets. In the continental United States, the CPP is expected to reduce emissions from existing affected sources by over 607 million metric tons per year in 2030 relative to 2012 levels.... Their modeling predicts that CCS

EOR retrofits can account for between 4 and 16 percent (depending on the scenario modeled) of the U.S. total CO2 reductions under the CPP."224 Comment 3: Commenters stated EPA has to give the industry time for the technology to develop and for it to be on an even playing field.

Response 3: The EPA did not find CCS to be part of the BSER for these sources. However, the EPA has noted that some existing EGUs with available space and accommodating layouts may find CCS

– or maybe partial CCS

– to be an appealing compliance option

. Thi s may be especially the case for sources that can take advantage of EOR opportunities

– much like the Petra Nova project at NRG’s WA Parish plant near Houston, TX

. These projects

– along with other projects such as the Kemper County IGCC facility and the B oundary Dam project

– will help to further develop the technology.

Comment 4: Commenters stated that if the EPA insists on deadlines far in the future, it could be bolder and look for the development of small, but growing numerical goals for carbon captu re and reuse. Commenters stated the investment impact of these goals would lead to an explosion of technology investment and innovation.

Response 4: See response to the previous comment.

Comment 5: Commenters discussed the need to further fund and promot e CCS, citing the importance of coal to the US energy portfolio.

Response 5: The EPA has, at several times, noted the importance of R&D in the further development and deployment of advanced technologies

– including CCS

. However, the primary sponsor of fede rally funded R&D for CCS is the U.S. Department of Energy (DOE).

The following are summaries of the specific public comments under this comment:

Commenters stated EPA's proposed NSPS and existing source standards make it far less likely that coal will main tain this significant and stable role, which will, in turn, stunt CCS/CCUS development. Commenters stated entities considering construction of a new EGU likely will not invest billions of dollars in CCS/CCUS that has not been demonstrated at full commercia l scale when a lower cost and less risky alternative (NGCC) is available. Commenters stated EPA's proposal fails to properly consider the combined effect of recent and ongoing EPA rulemakings in driving additional coal plant closures and how such closures will negatively impact the prospects of making CCS/CCUS commercially available. Commenters stated stronger support mechanisms will be needed to ensure that CCS/CCUS becomes commercially viable in time to facilitate climate objectives. Commenters stated tha t in lieu of the Clean Power Plan, it would recommend that the Administration focus its attentions on more robust support mechanisms for CCS/CCUS. Commenters stated the modest investments to date in CCS/CCUS have failed to reflect coal's relative importanc e in the nation's energy mix, while governmental support for other less significant fuels have exceeded their relative importance and future potential.

Commenters stated one way to combat the decreasing interest in the utilization of coal as part of

our na tion's energy future is through the promotion and funding of CCS technology.225 Commenters stated that bringing CCS to the marketplace is a costly enterprise and further research and development leading to commercialization is essential to continuing the prog ress of such facilities as Plant Barry in Alabama, the largest Carbon capture and sequestration effort so far. Commenters urged the Department of Energy to provide funding to further develop CCS technology essential to ensuring that coal remains a vital an d competitive asset in the United States' energy portfolio.

Comment 6: Commenters recommended that CCS be incorporated into the CPP and encourage efforts to incentivize its use.

Response 6: The EPA noted in the proposal, the existing fleet of fossil fuel

- fired EGUs vary greatly in size, location, available space, etc. and that integration of CCS technology at some locations would likely be very challenging and, thus, the EPA did not find CCS to be part of the BSER for these sources. Among the challenges i s the availability of space

– however, that is not the only challenge and integration of commercially available CCS technology at existing EGUs across the country would be an enormously expensive endeavor. The EPA has noted, however, that some existing EGU s with available space and accommodating layouts may find CCS

– or maybe partial CCS

– to be an appealing compliance option. This may be especially the case for sources that can take advantage of EOR opportunities

– much like the Petra Nova project at NRG’ s WA Parish plant near Houston, TX. See sections V.A of the final rule preamble of the CPP and Chapter 5 of the GHG Mitigation Measures TSD for CPP Final Rule for additional information.

The following are summaries of the specific public comments under this comment:

Commenters stated the most commonsense approach to cut pollution at power plants, carbon capture and sequestration (CCS), is largely absent and not supported by the rule in its current form. Commenters stated that discouraging the retrofittin g of existing fossil fuel

- fired EGUs with CCS places current jobs at risk, disincentivizes domestic investment into CCS technology, and is an impediment to the creation of new construction jobs as well as the preservation of current jobs in the energy sect or. Commenters stated EPA has not justified why our nation's number one natural resource, coal, when coupled with CCS to virtually eliminate carbon pollution, would not be embraced, supported and incentivized. Further, commenters stated, the EPA omits cons ideration of the Intergovernmental Panel on Climate Change's findings that deployment of CCS technology on fossil

- based energy systems is essential if the world is to meet any future target for stabilization of atmospheric GHG concentrations.

Commenters st ated the federal government and Congress see CCS as a value proposition, one where jobs are saved because power plants do not have to shut down and pollution is decreased. Commenters stated hundreds of millions of taxpayer dollars are invested into CCS Res earch Development and Deployment to foster new technological advances and curb pollution from our nation's fossil fuel

- powered generation sources: coal and natural gas. Commenters also stated through DOE funding, carbon capture plants have the potential of meeting the DOE's carbon capture cost goal of $40/ton for commercial applications. Commenters stated that ironically, the EPA cites the Energy Information Administration's fuel price projections which estimate that the226 CO2 reductions achieved through natu ral gas conversion or co

- firing at an average coal

- fired EGU would have costs ranging from approximately $83 to $150/metric ton. Commenters stated that recognizing the EPA's own assessment that CCS can eliminate up to 90% of CO2 emissions, it is challengin g to determine why the DOE's public goal of $40/ton was not referenced or cited in the CPP.

Commenters stated nineteen states have laws and regulations providing incentives for the deployment of carbon capture and storage technology. Commenters stated tha t following these effective strategies, the EPA should encourage the option to deploy CCS at existing power plants through an incentive mechanism, such as encouraging states to create set

- asides, bonus allowance, or comparable programs for the benefit of f irms that invest in partial or full CCS. Commenters stated a few other effective strategies include:

• Financial Support, such as grants or loans for CCS projects or CO2 pipelines

• Tax Incentives, such as tax credits, exemptions, or abatements for income,
pro perty, or sales taxes.

• Off

- Take Agreements, which provide a guaranteed buyer for the electricity or output from a CCS project.

• Utility Cost Recovery Mechanisms, which offer timely reimbursement of costs incurred during construction and operation or favorab le rates of return for regulated utilities' investments. Some states have explicitly included CCS as an eligible technology for cost recovery mechanisms.

• Eligibility of CCS in Electricity Generation Portfolio Standards or Voluntary Goals. When CCS is inclu ded in these standards, utilities can earn saleable compliance credits by generating electricity using CCS. Additionally, inclusion of CCS in portfolio standards or goals could facilitate utility cost recovery approval of CCS power projects, which is criti cal for financing.

• State Assumption of Long

- Term Liability for Sequestered CO2, which reduces the long

- term costs of CO2 injection for private project developers.

Commenters stated the final rule should include incentives, permitting protocols and address regulatory barriers to allow and promote the installation of CCS at fossil fuel

- powered facilities.

Commenters stated that EPA should reconsider the role of CCS retrofits within the BSER. Commenters stated that EPA's assessment of the technology rightly ac knowledges its current cost limitations; however, the technology is progressing rapidly. Commenters noted that since the publication of the proposed rule, Saskatchewan's Boundary Dam Unit #3 CCS retrofit has come on line

- yielding a 90% CO2 capture rate

- and two others are under construction in the U.S. (Kemper in Mississippi and Petra Nova in Texas). Commenters stated that while the proposed rule does nothing to exclude CCS from a state compliance strategy, they believe that in the near future, CCS will be " adequately demonstrated" and merit equivalent treatment with co

- firing as a component of the BSER in establishing future targets. Commenters also stated that given the227 enormous impact that the proposed rule would have on existing infrastructure, EPA is

enc ouraged to consider establishing or requiring state establishment of financial mechanisms to support CCS projects.

Comment 7: Commenters stated the rule encourages the abandonment of the technological development of other carbon

- cutting methods such as ca pture and sequestration.

Response 7: The EPA disagrees with this notion. The EPA noted in the proposal that some existing EGUs with available space and accommodating layouts may find CCS

– or maybe partial CCS

– to be an appealing compliance option. This may be especially the case for source s that can take advantage of EOR opportunities

– much like the Petra Nova project at NRG’s WA Parish plant near Houston, TX. States are free to include CCS projects in approval state plans. See sections V.A of the Final Rule preamble of the CPP and Chapter 5 of the GHG Mitigation Measures TSD for CPP Final Rule for additional information.

Comment 8: Commenters stated the EPA needs to do more to incentivize innovative GHG capture technology.

Response 8: The EPA has written about promotion of advanced CCS t echnology in the preamble for the companion section 111(b) rulemaking for newly constructed sources. The EPA has noted, however, that some existing EGUs with available space and accommodating layouts may find CCS

– or maybe partial CCS

– to be an appealing compliance option. This may be especially the case for sources that can take advantage of EOR opportunities

– much like the Petra Nova project at NRG’s WA Parish plant near Houston, TX. See sections V.A of the Final Rule preamble of the CPP and Chapter 5 of the GHG Mitigation Measures TSD for CPP Final Rule for additional information.

The following are summaries of the specific public comments under this comment:

Commenters stated EPA should consider the valuable role that beyond

- the

- fence

- line GHG removal technologies may play in reducing excess GHG emissions. Commenters stated EPA should actively consider funding research and development of these technologies and pilot regulatory strategies in which states may be allowed on a limited basis to apply GHG re ductions from DAC and similar GHG capture technologies to their emissions budgets.

Commenters stated EPA should consider expanding the flexibility it has already identified in Building Blocks 3 and 4 to provide both for later

- in

- time and beyond

- the

- fence

- l ine measures for GHG reductions that would allow for application of DAC technologies to meet GHG emissions reduction goals. Commenters stated that expanding the building block approach to include DAC technologies would further Congress's intent that the Cl ean Air Act be used to promote technological innovation in efforts to help achieve the same policy goals behind EPA's existing and proposed GHG regulations for mobile and stationary sources and the broader environmental and public health goals of the Clean Air Act.228 Commenters stated that although the GHG emissions reductions measures proposed under Building Blocks 3 and 4 are not imposed directly on the source of emissions at EGUs at the time those emissions occur, they nevertheless have an impact on the ov erall amount of GHGs in the atmosphere, and they are supportable under the Act on that basis. Commenters stated there is thus nothing conceptually to bar EPA from taking an additional step with respect to the temporal flexibility of BSER that EPA has alrea dy identified and allowing states to meet emissions limitations with a focus on the time period after which GHG emissions have been released into the ambient air. Commenters stated these emissions remain "emissions" of concern long after they leave a point source, and there is thus a basis for allowing use of within

- the

- fence DAC technology that further reduces these emissions as part of Building Block I.

Commenters stated that there is also nothing conceptually to bar EPA from allowing states to meet emiss ions limitations through the use GHG removal technologies that are implemented at locations adjacent to or under contract with regulated EGUs. Commenters stated whereas Building Blocks 1 and 2 emphasize GHG emissions reduction at the EGU sites, Building Bl ocks 3 and 4, with their emphasis on demand

- side efficiency and increases in renewable energy sources, both go "beyond the fence line" to ensure that GHG emissions reductions are achieved. Commenters stated the geographic flexibility to BSER that EPA has i ntroduced in the proposed rulemaking should be able to incorporate GHG removal from DAC and other technologies that are not located within the EGU fence line.

Comment 9: Commenters stated the proposed rule may diminish investment in algae

- based and other CCU technologies.

Response 9: The EPA has specifically addressed CCU opportunities

– including the use of captured CO 2 to produce algae

- based biofuels

– in the final preamble and how they may be included in approvable state plans. See sections V.A of the Final Rule preamble of the CPP and Chapter 5 of the GHG Mitigation Measures TSD for CPP Final Rule for EPA’s response to this
comment.
The following are summaries of the specific public comments under this comment:

Commenters stated the proposed rule as wr itten risks diminishing investment in, and development of, algae

- based and other CCU technologies with the greatest potential to reduce emissions from existing fossil

- powered EGUs. Commenters stated CCU is critically important not only in the U.S., but is vital to reducing the impact of the rapid deployment of fossil

- powered EGUs in China and other developing nations. Commenters stated that without strong options for conversion and use of CO2 from these facilities, global GHG emissions will continue to incr ease unabated. Commenters stated EPA should ensure that the proposed rule provides the greatest possible encouragement for these vital technologies.

Commenters stated algae

- based CO2 conversion offers a diverse set of economic and environmental benefits, including high potential yield per acre, the ability to grow on land not suited for agriculture and in brackish or wastewater, absorption of CO2, and relative ease of conversion into fuels and products. Commenters stated algae's potential for GHG reduction s is229 among its most desirable characteristics, noting that peer reviewed lifecycle analyses of two of the leading commercial demonstration algae production facilities show CO2 reductions of 68 to 80 percent on a full lifecycle basis versus petroleum

- based alternatives. Commenters also stated algae

- based renewable diesel is approved by EPA under the Renewable Fuel Standard as a qualified advanced biofuel with lifecycle GHG emissions reductions of greater than 50 percent verses petroleum

- based diesel. Comment ers also discussed algae oils, noting the benefits of algae carbon capture in the reduction of CO2 emissions from deforestation for palm oil production. Commenters also stated algae production has the potential to scale to very significant levels of

commer cial production, providing additional discussion on algae and other CCU platforms.

3.8. 7 Other

This section discusses comments that do not otherwise fit into one of the above subsections concerning use of CCS as an emissions reduction method. The EPA is not identifying CCS at coal

- fired steam EGUs as part of the BSER, but it remains a control measure that some affected EGUs may be expected to implement.

Commenters have raised a number of issues related to the subsection which are organized by topics (comm ents) below. Responses are also provided for these topics. (Below the response, comment summaries are noted.)

Comment 1: The EPA should encourage carbon capture and utilization (CCU).

Response 1: The EPA has specifically addressed CCU opportunities in th e final preamble and how they may be included in approvable state plans. See sections V.A of the Final Rule preamble of the CPP and Chapter 5 of the GHG Mitigation Measures TSD for CPP Final Rule for EPA’s response to this comment.

The following are summar ies of the specific public comments under this comment:

Commenters described the benefits of carbon capture and utilization and said that the EPA should encourage its use.

Commenters described the benefits of using Carbon Capture and Utilization (CCU) technologies using a wide range of platforms to convert CO2 into renewable fuels, chemicals, fertilizer, plastics, feed ingredients and other products, which also creates high tech and manufacturing jobs in local communities across the country. Commenters said that the single most promising and cost

- effective option for reducing GHG emissions from existing power plants is using CO2 as a feedstock to produce algae

- derived product s, which generate revenue to off

- set capital and operating expenses. In contrast with CCS, commenters stated, algae CCU has no dangerous byproducts and with closed photobioreactors, such as those developed by HTB, algae scrubbers can be configured in multi

- storied buildings reducing the geographic footprint and enabling their use at nearly every power generation facility in the country, and in any latitude or climate. Unlike CCS, commenters added, with CCU there is no need to store and transport pressurized230 CO2 in expensive pipelines and no need to be in close proximity of special geologic formations or deep well drilling operations, so the initial capital expense and operating costs for CCU are much less than CCS. Commenters added that any time carbon is re cycled for energy production or sequestered for long periods of time in a variety of products from plastics to paint thickeners, CO2 emissions are reduced in the aggregate. Commenters said accounting for these reductions may be more complex, but it is cert ainly possible and it would be a mistake not to do so. Finally, commenters said, with CCS all the added expense and parasitic load of capture, purification, compression and underground injection is borne by the ratepayer, while CCU offers a market

based al ternative where revenue from algae sales off

- set operating expenses and provide healthy ROI to investors. Commenters discussed how algae can grow using unfiltered flue gas and their demonstration project.

Commenters provided extensive comments and referen ces on the commenter s ' algae

- based process for economically producing biofuels by consuming the CO2 being emitted by power companies which has at least a 60% reduction in GHG emission compared to emissions from traditional gasoline. Commenters stated that this technology negates the need for costly, unproven solutions such as underground storage of CO2 and solutions too far outside the plant fence that are on shaky legal ground. Commenters said that Algenol's patented technology enables the production of th e four most important transportation fuels (ethanol, gasoline, diesel, and jet fuel) for around $1.30 per gallon by combining CO2, sunlight, proprietary algae, and saltwater at production levels of 8,000 total gallons of liquid fuel per acre per year. In a two

- step process, Commenters said that they first produce ethanol directly from the algae utilizing a Direct to Ethanol technology and second, a bio

- crude through hydrothermal liquefaction conversion of the spent algae once the ethanol production process is complete. Commenters stated these novel, low

- cost techniques have the added benefits of consuming CO2 from industrial sources, not using farmland or food crops as feedstocks, and being able to provide more freshwater than fuels produced. Commenters adde d that all of the Algenol low carbon fuels produced also displace equivalent gallons of fossil fuels from being burned. Commenters described the company's growth, investments, and activities and said that they are actively evaluating potential sites, meeti ng with industrial CO2 providers, completing engineering designs, site ground testing, and pursuing permitting for their first very large commercial project to be launched in the near future.

Commenters agreed that using algae to create integrated bio

- ref ineries to produce gasoline, diesel, jet fuel and bioproducts is a way to reduce power bills for low income neighborhoods.

Commenters stated that to ensure maximum potential for carbon utilization, reuse and even sequestration, special consideration also should be granted to algae producers that would be subject to emissions regulations. Commenters said that this will enable e ntrepreneurial companies to experiment with novel technologies without being encumbered by regulatory requirements. To ensure that this technology and industry has a chance to succeed, commenters said that the EPA must create a nurturing environment for it by acknowledging carbon capture and utilization in the final Rule, and states should be encouraged to adopt policies that provide incentives to both carbon emitters and carbon utilizers to develop CO2 transfer mechanisms. Commenters concluded such policie s will enable the development of new technologies that have the potential to significantly reduce CO2 emissions.231 Commenters agreed that the EPA should recognize CO2 reductions resulting from innovative approaches to carbon utilization and recycling. Comme nters said that assigning these actions a credit and allowing these reductions to be used as options in state compliance plans would create an incentive for developing and advancing carbon utilization and recycling technologies, ultimately leading to less CO2 in the atmosphere. Commenters stated that examples of innovative carbon uses include:

• Algae farming using CO2 from power plant flue gas;

• Production of liquid fuels using CO2 from power plant flue gas;

• Development of carbonates from mineralization of CO2 from power plant flue
gas;

• Use of fly ash to reduce the amount of Portland cement used in concrete (i.e. CO2 emissions not occurring from additional Portland cement production); or

• Tree planting and forest preservation.

Commenters said that the EPA should develop a rule structure which: (1) recognizes the potential for carbon capture and utilization (CCU) in any and all State Carbon Pollution Plans; and (2) encourages states to foster breakthrough innovative technologies that can further drive down carbon pollution emissions. Commenters said that the final rule should clearly indicate that carbon utilization is an acceptable component in the EPA's Building Blocks approach for use in state emissions reduction plans. By recognizing CCS in the draft rul e, commenters said that the EPA encourages states to adopt an inferior technology, and by failing to recognize CCU as a viable solution it discourages states from adopting CCU, which is a less expensive and better way to reduce GHGs. Commenters said that a ffirmative recognition of CCU would provide states and sources of private capital with the confidence to invest in this highly promising GHG mitigation solution, which significantly reduces the cost of compliance.

Alternatively, commenters requested that the EPA acknowledge the potential for CCU to reduce facility emissions within the fence

- line under Building Block One and create incentives for innovative technologies to be deployed under that and other blocks. Commenters said that a more aggressive timef rame for state plans and goal achievements, backed up by quantitative analysis of GHG reduction from emission control technologies, would incentive capital to capture and utilize CO2. Commenters asked the EPA to consider allowing emissions banking for cred its achieved at any point between the date of the proposal and later reasonable further progress demonstrations. Commenters were concerned that the current approach is insufficient to drive the bold technology investments needed to make a long

- term differe nce in this nation's power generation assess and global emissions. Commenters described the benefit that promotion of CCU technology could have on global emissions if it is seen as a blueprint by foreign countries (i.e., China and India) and international funding bodies. As a result, commenters said that CCU should be highly visible in the rule, preferably as its own "block" of strategies available to the states.232 Commenters said that if emitters can profit greatly by the sale of CO2 to Algenol, this will

en sure the rapid adoption of the GHG reducing technology. The rule should provide explicit additional credits to states for emissions reductions that are derived from innovative technologies, such as CCU, commenters said, and it should provide credits that e ncourage the widespread deployment of such technologies. Commenters compared this approach to the one that the Agency recognized would be effective and used in its efforts to encourage innovation in the automotive sector, where it provided additional compl iance credits for advanced technologies that reduce GHG emissions and their permeation through the fleet. See Fact Sheet: EPA and NHTSA Set Standards to Reduce Greenhouse Gases and Improve Fuel Economy for Model Years 2017

- 2025 Cars and Light Trucks at 7

- 9 (available at http://www.epa.gov/otaq/climate/documents/420f12051.pdf). Commenters explained that this same approach should be adopted here as a means to promote the establishment of vital technologies that might not otherwise yet be cost effective but th at will be essential for meeting the emissions guidelines now and in the future.

Providing an additional comment on rule structure, commenters said that the four building blocks proposed by the EPA do not appear to make room for control technologies that address the problem at the source, a fairly rare occurrence within the Clean Air Act. Instead, commenters said, the EPA resorts to four indirect solutions, including generator efficiency improvements, substituting natural gas combined cycle generation, sub stituting renewable energy or using demand side energy efficiency to reduce emissions. Commenters advocated for the addition of language that would include capturing carbon economically and utilizing and monetizing this carbon through beneficial solutions such as fuels, green chemicals or building materials. Commenters said that the EPA should recognize the full value of emissions reductions created by these carbon utilization solutions. Commenters added that this approach would help to maintain the reliabi lity benefits provided by base load coal generation.

Comment 2: Commenters stated the EPA should clarify that states can apply early emission reductions from CCS toward compliance with required emission performance levels.

Response 2: The EPA has speci fically addressed CCS opportunities in the final preamble and how they may be included in approvable state plans. See sections V.A of the Final Rule preamble of the CPP and Chapter 5 of the GHG Mitigation Measures TSD for CPP Final Rule.

The following are summaries of the specific public comments under this comment:

Commenters urged EPA to clarify that early action is allowable under state plans, and recommended that EPA allow and reward early action reductions after the date of the Existing Source proposal (e.g. June 14, 2014). Commenters stated this approach is the most likely to fully account for actions undertaken to comply with state emission performance limits. Commenters stated it is important to motivate the deployment of key compliance technologies such as CCS. Commenters stated the approach recommended here simply helps to mitigate a disincentive to acting now. Commenters also stated that identifying additional mechanisms for rewarding early action could also be important tools that EPA should consi der, particularly with respect to strategic technologies such as CCS. Commenters requested EPA clarify that all emission233 reductions resulting from early actions taken after the date of proposal should count toward state compliance. Commenters emphasized th is issue because the Existing Source proposal appears primarily focused on the implementation of renewable energy and energy efficiency projects. Commenters stated that by focusing on these two compliance options, they are concerned that states may not rec ognize that CCS and other compliance options are also covered by the early action approach. Commenters stated EPA can readily address their concern by mentioning CCS and other such compliance options in the discussion of early action in the final rule. Com menters stated that delay in the implementation of CCS projects in the US

- where the technology is poised to take off, especially with the support of comprehensive policy frameworks which have heretofore been lacking

- will represent an enormous missed op portunity and almost certainly delay the global spread of this technology. Commenters stated that a decision by EPA to encourage and reward early action will send an important signal to power plant owners considering new and retrofit carbon capture project s.

Comment 3: Commenters stated the EPA should include technical and policy information on CCS in the materials the Agency provides to states.

Response 3: The EPA has specifically addressed CCS and CCU opportunities in the final preamble and how they may be included in approvable state plans. See sections V.A of the Final Rule preamble of the CPP and Chapter 5 of the GHG Mitigation Measures TSD for CPP Final Rule for EPA’s response to this comment.

The following are summaries of the specific public comments under this comment:

Commenters stated they understand EPA's support for EE and RE as important compliance options under the proposed emission guidelines, noting the web

- based Toolbox with additional information on these building blocks. Commenters stated concern that EPA has not provided comparable information on other compliance options that are not part of the "best system of emission reduction," but are identified in the Existing Source proposal as alternative ways to comply with state emission performance limits. Commenters stated that many states are likely to rely disproportionately on information and guidance provided by EPA as they identify and analyze various compliance options and develop section 111(d) plans. Commenters stated that if EPA focuses on only a few approaches toward reducing CO2 emissions from the power sector, it is less likely that states will look at a broader range of technologies. Commenters urged EPA to provide additional information on different types of state CCS polici es in the Clean Power Plan Toolbox. Commenters noted that there are a variety of policy approaches that have been implemented at the state level, including severance tax reductions for EOR operations using anthropogenic CO2; cost recovery approval for regu lated utilities that pursue carbon capture; tax credits, exemptions or abatements; and inclusion of CCS in low

- carbon portfolio standards. Commenters also encouraged EPA to expand the AVERT model to include CCS as a compliance option. Commenters stated tha t EPA's encouragement of CCS projects is fully consistent with the Agency's conclusion that CCS technology is commercially viable today.234 Comment 4: Commenters recommended the EPA include carbon capture and utilization (CCU) technologies in the proposal.

Response 4: The EPA has specifically addressed CCU opportunities in the final preamble and how they may be included in approvable state plans. See sections V.A of the Final Rule preamble of the CPP and Chapter 5 of the GHG Mitigation Measures TSD for CPP F inal Rule for EPA’s response to this comment.

The following are summaries of the specific public comments under this comment:

Commenters stated that rather than limiting consideration to CCS, EPA should also assess carbon capture and utilization (CCU) as a far less costly, and therefore more viable, system of emissions reduction. Commenters stated by transforming carbon emissions from a costly waste that must be managed and properly disposed of into a valuable feedstock, CCU has the potential to transform t he dynamics of the power market and make CO2 a valuable commodity asset, not liability. Commenters stated that solutions that involve capturing carbon at the source currently do not fit neatly in any of the blocks proposed in the rule, and the rule should catalyze the states to facilitate market

- based carbon capture and utilization solutions wherever they make sense. Commenters stated that CCU would allow utilities and their business partners to sell pure CO2 in various specifications within a wide range of prices up to $35

- 50/tonne, and unpurified NG flue gas CO2 for $1/tonne. Commenters stated that the general thrust should be to encourage carbon capture investments by including profitable CO2 end use with net carbon benefits in the overall target emission limits, and as a result, the carbon capture investments would not have to be supported by the rate base, and would be a benefit to the rate base, therefore these would be easy for utilities to justify. Commenters provided additional information on the ben efits of Algenol CCU, noting the technical and legal basis for inclusion of this form of CCU in the rule.

Commenters stated that CCU would be fully consistent with all the criteria to approve state plans: (1) Enforceable measures; (2) Emission performance ; (3) Quantifiable and Verifiable; and (4) Reporting and Corrective actions. Commenters stated that given that CCU in the form of an Algenol facility is a point source solution with hard assets on the ground, and a full array of control and monitoring equi pment, the states should have no difficulties in fitting CCU targets or incentives within an overall GHG state plan that needs to meet EPA muster. Commenters stated EPA should acknowledge and encourage these approaches as part of this rulemaking.

Commenters urged EPA to include in its final rule CCU as a valid

- and encouraged

- carbon reduction measure that would help states meet their emissions reductions goals. Commenters stated there is a plethora of algae technology platforms that convert CO2 into renewable fuels, chemicals and products, including fertilizer, plastics and feed ingredients. Commenters stated algae biofuels and renewable chemical producers often purchase commercial CO2 as a feedstock. Commenters stated if EPA makes it clear that CCU is a valid carbon reduction measure in its final rule, there could be a significant opportunity for algae producers to partner with EGUs not only to help eliminate CO2 emissions from EGUs, but to actually utilize those emissions to make even further re ductions.

Commenters stated the final rule should include language that recognizes that cost effective and highly scalable CCU technology could emerge as the rule is implemented and should require235 states to develop plans that explore and recognize developi ng technologies. Commenters provided additional information on their product and stated that in the past several years, technologies developed by companies like Skyonic, Calera, and New Sky have demonstrated the benefits of carbon conversion and utilizatio n over amine

- based gas separation technologies.

Commenters encouraged the EPA to include language in the final rule indicating that carbon utilization would be an acceptable component in the state emissions reduction plans. Commenters stated such an affirm ative recognition would provide states and sources of private capital with the confidence to invest in this highly promising CO2 solution while helping to create a market for CO2 that reduces the cost of compliance

Commenters stated algae

- based CCU is clea rly cost advantaged over CCS. Commenters stated that, Accelergy, in a November 2014 presentation to the National Rural Electric Cooperative Association (NRECA), estimated the cost of its algae bio

- fertilizer CCU platform at $4 to $11 per ton of CO2 capture d, with up to 60 additional tons of CO2 reduction realized for every ton of CO2 captured through reduced application of nitrogen

- based fertilizer and ongoing carbon and nitrogen uptake by the algae once applied to the soil. Commenters stated this represent s a cost reduction of up to 95 percent versus CCS. Commenters also stated that at over 100 gallons of biofuel produced per ton of CO2, the value of biofuel produced from algae

- based CCU is likely to exceed $300 per ton of CO2. Commenters stated algae proje ct developers are therefore well positioned to mitigate, offset, or even negate the cost of carbon capture, providing a CO2 reduction mechanism that minimizes the cost to ratepayers. Commenters also stated algae

- based CCU also does not require the added ex pense and parasitic load of CO2 compression and underground injection associated with CCS. Furthermore, commenters stated that with CCS, the entire cost of capture, purification, compression and underground injection is borne by the ratepayer whereas CCU o ffers a market

- based alternative for CO2 that minimizes cost to the ratepayer by turning CO2 from a waste into a commercial resource. Commenters also stated that algae CCU offers a way to offset the cost of compliance while reducing the use of petroleum.
Commenters stated Algenol can secure carbon at costs ranging between $1 and $40 per tonne, and the manufacturer will absorb the costs because their fuels can be sold at a value of more than $380/tonne of CO2 utilized. Commenters stated that since the fuel produced by Algenol is cheaper to produce than alternative options, it means that there will be net positive benefits to consumers and utility shareholders.

Commenters stated CCU produces real, quantifiable and permanent reductions in CO2 emissions. Comme nters stated many CCU applications, such as algae conversion to chemical intermediates and plastics, directly sequester CO2 in enduring product, and other applications, such as production of algae

- based soil amendments and bio

- fertilizer, can produce ongoi ng reductions in atmospheric CO2 well beyond the life of individual organisms. Commenters stated even when subsequently combusted as a transportation fuel, CO2 utilization produces ton

- for

- ton emissions reductions by displacing additional fossil fuel combu stion. Commenters stated in this way, carbon capture and conversion to biofuel achieves CO2 emissions reductions comparable to CCS and is a preferred option to reuse for EOR, which by definition increases fossil carbon extraction and subsequent combustion. Commenters referenced a study by Georgia Institute of Technology which provides the first direct comparison of CO2 reductions achieved using algae

based CCU versus application of CCS for the same power generation facility. Commenters stated236 that the analy sis found that algae

- based CCU results in a greatly advantaged carbon footprint relative to business as usual, and emissions similar to CCS, even when subsequent biofuel combustion is included. Commenters stated that for biofuels produced with lifecycle em issions reductions greater than 75 percent relative to petroleum, CCU is advantaged with respect to CCS.

Commenters stated that to ensure compliance with the proposed standard and public confidence in CCU as a GHG mitigation strategy, EPA should include i n the final rule adequate monitoring and reporting requirements for CCU projects. Commenters stated that for example, EPA could set general criteria and require affected EGUs to submit a Monitoring, Reporting and Verification Plan (MRV Plan) for EPA's appr oval on a case

- by

- case basis, similar to MRV Plans prepared by entities undertaking geologic sequestration pursuant to 40 C.F.R.

- 98.448 subpart RR. Commenters stated this approach would ensure that affected EGUs remain fully responsible for achieving emi ssions reductions.

Commenters also stated that EPA should restrict its regulation under the proposed existing source rule to fossil

- fired EGUs, and nothing in the rule should involve regulation of any downstream recipients of captured CO2. Commenters stat ed that appropriate monitoring and reporting requirements will ensure that affected EGUs remain responsible for the proper disposition of CO2 after it is captured, and EPA has ample authority to establish such monitoring requirements under Section 111.

Co mmenters agreed that accounting of CO2 reductions for CCU projects must be done in a manner that avoids double counting of reductions resulting from CO2 uptake and ensures additionality. However, commenters stated there currently exist no federal programs under which downstream recipients of captured CO2 may claim specific reductions. Commenters stated the federal Renewable Fuel Standard (RFS) does include standards for lifecycle GHG reductions of qualifying fuels, but only for the purposes of generation of Renewable Identification Numbers (RIN) and subsequent demonstration of compliance with renewable fuel blending requirements. Commenters stated renewable fuels produced from captured CO2 that meet RFS requirements for RIN generation rightly qualify for the program, but do not receive specific credit under the program for CO2 reductions. Thus, commenters stated, there is currently no threat that reductions credited under the proposed rule will receive duplicate credit under another Clean Air Act program. Com menters also stated that under economy

- wide CO2 regulations, such as those proposed in 2009 under H.R. 2454, the American Clean Energy and Security Act of 2009, appropriate measures would be required to prevent double counting. Commenters stated industry

a nd the environmental community worked together to include language in H.R. 2454 to establish a simple methodology to prevent double counting. Commenters stated that a similar approach could be adopted administratively by EPA should downstream CO2 recipient s be subsequently regulated under future EPA action, such as under a federal Low Carbon Fuel Standard.

Commenters stated that while the proposed rule does not mandate any single method for meeting the CO2 reduction targets, it does, however include a disc ussion of CCS as a method that states can use to meet its target without discussing CCU. Commenters stated concern that EPA is missing an important opportunity by failing to recognize CO2 utilization as a method that states can use to meet their targets. C ommenters stated concern the proposed rule's silence on CO2 utilization will effectively discourage states from including utilization in their state plans, thereby slowing progress in development of a technology platform with great potential for237 monetizing CO2 and reducing atmospheric CO2 in a productive way. Commenters also stated that by referencing CCS and not CCU the proposal also adopts a preference for the disposal of CO2 over its reuse. Commenters stated this violates the well

- established waste manag ement hierarchy set forth in the Pollution Prevention Act (P2 Act), which prioritizes prevention, reduction and recycling of waste over treatment or disposal. Commenters stated that in light of the technical feasibility and commercial availability of carbo n utilization technologies, the proposed rule should encourage the utilization of CO2 as a preferred alternative to sequestration.

Commenters stated that in addition to benefitting ratepayers directly by offsetting the cost of compliance for fossil

- fired EGUs, broad deployment of CCU has the potential to provide substantial additional benefits to the economy through job creation. Commenters stated that currently the algae sector employs, directly and indirectly, more than 10,000 workers at approximately 10 0 companies, as well as at academic and government research projects around the country, and many suppliers of specialized equipment and services. Commenters estimated that once algae fuel production reaches full commercial scale the industry could support approximately 100,000 direct jobs, and if one includes these ancillary jobs, the industry is expected to create over 200,000 jobs that will be steady and high

- paying, requiring workers spanning across a wide variety of educational backgrounds and skills. Commenters discussed public support for algae

- based CCU and urged EPA to explicitly include CCU in its final rule.

Commenters stated the broad demonstration and deployment of carbon capture and utilization technologies makes clear that CCU is at least as adequately demonstrated as CCS, and should be available to states to help meet their 111(d) obligations. Commenters stated that the use of CO2 as a feedstock to produce algae

- based fuels and products is among the most promising options for reducing CO2 emi ssions from existing and future CO2

- producing power plants. Commenters stated that its broad suite of commercial developments illustrate that algae

- based CO2 utilization has now clearly advanced to the point where it can and should be available to states t o help meet their greenhouse gas goals. Commenters welcomed the opportunity to participate in reducing emissions of CO2 from the power sector by partnering with utilities to utilize captured carbon as a feedstock, transforming CO2 from an expensive waste d isposal issue into a resource that will benefit industry, the environment and ratepayers. Commenters stated a clear signal from EPA that CCU projects are eligible under the Clean Power Plan would greatly accelerate adoption of this technology.

Commenters provided a discussion on the historical development of algae

- based fuels and products, noting that algae biomass research, development and deployment are underway throughout the U.S. Commenters stated that research has evolved rapidly, and algae

- based carb on utilization is now being demonstrated at scale, including at DOE

- funded integrated biorefinery (IBR) projects and pilot projects in Iowa, Hawaii, Kentucky, and elsewhere. Commenters highlighted several projects, including Sapphire Energy production of a lgae

- based crude oil at its 100

- acre Integrated Algal Biorefinery in Columbus, New Mexico, Florida

- based Algenol operation of its 36

- acre IBR project in southern Florida to convert CO2 to ethanol and bio

- crude oil from algae, Duke Energy and the University of Kentucky operating a demonstration scale algae CCU unit at Duke's East Bend coal

- fired power generating station in Union, KY, converting CO2 flue gas from a coal

- fired power plant into algal biomass at an onsite photobioreactor, Accelergy Corporation, a leading coal

- to

- liquids (CTL) technology developer, is currently validating its TerraSync technology for algae

- based conversion of CO2238 from CTL fuel production into bio

- fertilizer, and BioProcess Algae deploying their algae CO2 utilization platform at a Green Plains Renewable Energy ethanol plant in Shenandoah, Iowa. Commenters also stated that algae technology developers Cellana and Renewable Algal Energy have recently signed offtake agreements with Neste Oil, a leading oil refiner, for algal oil produce d at planned commercial algae production facilities, and in November, Mississippi

- based Algix, LLC, opened its first commercial facility for production of algae

- based bioplastics. Commenters also stated that beyond fuels and plastics, several leading algae biomass developers have recently signed deals to market algae

- derived ingredients for human and animal nutrition, personal care, cosmetics and other high value markets, and a wide range of other technologies for beneficial use of CO2 are also under develo pment.

Comment 5: Commenters stated the EPA should encourage states to use carbon capture mechanisms as a compliance tool.

Response 5: The EPA has specifically addressed CCS and CCU opportunities in the Final Preamble and how they may be included in app rovable state plans. See sections V.A of the final rule preamble of the CPP and Chapter 5 of the GHG Mitigation Measures TSD for CPP Final Rule.

The following are summaries of the specific public comments under this comment:

Commenters stated EPA should al low all activity that captures carbon, including verifiable offsets, to count towards compliance goals. Commenters specifically stated that the proposal ensure that CO2 emissions captured and sequestered from industrial facilities such as the Great Plains Synfuels Plant can be used toward compliance. Commenters stated substantial resources were invested in taking early action to process, pressurize, and export CO2 for sequestration, which should be recognized in this rulemaking. Commenters also stated that EPA should permit states to include innovation such as the Great Plains Synfuels Plant in their plans.

Comment 6: CCS must be strictly enforced.

Response 6: As noted in the companion section section 111(b) rule for newly constructed sources, the EPA has put measures in place to adequately monitor CCS

– both at the stack, during transportation, and during and after the injection process

. See section V. N of the preamble to the F inal Rule for section 111 ( b )

. A lso section V.A of the Final Rule preamble of the CPP and Chapters 3 and 5 of the GHG Mitigation Measures TSD for CPP Final Rule for additional information.

The following are summaries of the specific public comments under this comment:

Commenters stated for the Clean Power Plan to be viable, especially as it pertains to CCS, it must be strictly regulated and enforced if it is to be any kind of viable option for the reduction of carbon in the atmosphere.239 Comment 7 : Commenters stated the elimination of bur ning bio

- mass as well as CCS, which those processes are typically sited in EJ communities should not really be viable options in their case to receive credit for emission reductions. Commenters stated that should really be reconsidered.

Response 7 : See section V.A of the Final Rule preamble of the CPP and Chapter 3 of the GHG Mitigation Measures TSD for CPP Final Rule for the EPA’s response to this comment. A discussion regarding the use of some biomass feedstocks for compliance purposes can be found in s ection VIII.I.2.c and s ection VIII.K.1 of the preamble for CPP Final Rule

.

Comment 8 : Commenters stated Canada and the U.S. have collaborated extensively on CCS development and hopes that the final rule continues to encourage its use where appropriat e. Commenters stated the ESPS proposal acknowledges the continued role that fossil generation will play in the energy mix and the importance of carbon capture and sequestration (CCS) projects, like the Boundary Dam plant in Saskatchewan.

Response 8 : The EPA agrees that the SaskPower Boundary Dam CCS project is a vitally important project in helping to further develop and promote CCS technology.

Comment 9 : Commenters stated they are hopeful that in the next 10 to 20 years carbon sequestration and st orage becomes a feasible option for the development of new coal generation facilities given the abundance of fuel in their state. Commenters stated technology improvements for carbon sequestration and storage may allow for the future development of new coa l generation facilities. Commenters stated coal is an abundant in Utah and they look for a feasible solution to bring coal back into the discussion of future power generation.

Response 9 : The EPA agrees that CCS technology provides a pathway for continued use of coal for power generation. The EPA has written extensively about the state of CCS technologies in the companion rulemaking under section section 111(b) for newly constructed EGUs. Commenters should see that preamble and associated supporting documen ts section 111(b) of the companion section section 111(b) standards for GHG emissions from new, modified and reconstructed sources.

Comment 1 0 : Commenters asked for clarification regarding use of CCS projects in goal attainment.

Response 1 0 : The EPA has provided information on CCS and CCU and their inclusion in state plans. See section V.A of the Final Rule preamble of the CPP and Chapter 5 of the GHG Mitigation Measures TSD for CPP Final Rule for additional information.240 The following are sum maries of the specific public comments under this comment:

Commenters stated the suggested use CCS projects to meet the goals of GHG reductions needs to be clarified by EPA so that the negative effects of such projects do not outweigh the positives. Commen ters stated it has opposed the Hydrogen Energy California (HECA) carbon capture and sequestration project since 2008, which is federally subsidized and currently before the California Energy Commission. Commenters stated HECA represents the worst way possi ble to use CCS as a means of reducing GHG emissions from power generation. Commenters stated that HECA:

• will remove hundreds of acres of prime farmland from production.

• will use millions of gallons daily of water suitable for irrigation in order to cool it self in a farming area experiencing periodic and severe shortages of irrigation
water.

• will emit hundreds of tons of criteria air pollutants in a region which already has the worst air in the nation.

• will involve the transportation of coal by rail and truc k from outside California and into the San Joaquin Valley.

• will present new exposure to low income people of color in towns like Buttonwillow, Tupman, and Wasco.

• will need more than 900 heavy duty truck trips daily into and out of the plant.

• will produce f ertilizer which itself will become a GHG and almost no new power to the grid.

• will ironically be used for enhanced oil recovery.

• will emit several hundred thousand tons of CO2 into the atmosphere.

Commenters stated some, or all, of the above points sugge st that CCS projects such as HECA will have marginal or negative effects on reducing CO2 from the atmosphere and large negative effects in terms of resource use and air pollution.

Comment 12: Commenters stated the EPA should recognize development of other CCS strategies.

Response 12: The EPA has included additional information on the use of CCU technologies

– such as production of cement and other building materials in the final CPP preamble

. See section V.A. of the preamble to CPP Final Rule

.

The following are summaries of the specific public comments under this comment:241 Commenters stated EPA should include language that recognizes the viability and benefits of developing carbon capture and sequestration in cement, building and road materials. Comm enters stated this is a highly promising, scalable sequestration strategy and it would be a terrible mistake to exclude this sequestration pathway.

3.9 NEW NGCC CAPACIT Y

This section addresses the EPA's request for comment in the proposed rule on whether it should include new NGCC capacity as a component of BSER for BB2 and/or BB3 and therefore include such capacity in establishing state goals. Some comments also address n ew NGCC units as a potential compliance tool. Commenters both agreed and disagreed with these concepts and described legal and practical issues associated with implementing this option. Responses to the individual comments are discussed below along with su mmaries of the specific comments.

Comment 1: Commenters addressed whether additional new NGCC growth is likely and whether it would be available for generation shifting.

Response 1: The EPA’s modeling projects new NCGG capacity to be added in future yea rs. New NGCC units are subject to the standards of performance set in the section section 111(b) final rule. New NGCC units are not affected EGUs under this section 111(d) final rule. For the EPA's response to this comment see section V.A and V.D of the fi nal rule preamble of the CPP and the Natural Gas Pipeline and Electricity Transmission section of Chapter 3 of the GHG Mitigation Measures TSD for CPP Final Rule supporting the final CPP. The preamble section VII.D addresses leakage concerns that states mu st address for generation and emissions shifting to unaffected units.

The following are summaries of the specific public comments under this comment:

Some commenters believed that additional natural gas plant expansion is likely. Commenters pointed to the amount of new NGCC capacity constructed from 2003 to 2012 (119 GW) as confirmation that it is reasonable to anticipate a continued rate of expansion of this well

understood technology. Commenters added that this conclusion is affirmed by the IPM complianc e modeling of the Clean Power Plan conducted by EPA, which also affirmed that the costs of new NGCC are reasonable. Commenters stated the IPM model selected new NGCC (even though NGCC was not included to set the targets), which demonstrates that the costs of those plant builds are least

- cost and therefore reasonable. In addition, commenters said that financial analysts such as Lazard illustrate that new NGCC is one of the lower cost generation resources available to power companies today.

Commenters describ ed how a number of utilities have recently retired coal

- fired power plants and replaced the generation capacity with new NGCC and stated that this shows that new NGCC capacity is a predictable means of reducing carbon pollution rates and should be included in242 BSER. Other commenters noted new NGCC capacity expected to come on

- line soon in Louisiana, Tennessee, and Virginia which is not included in EPA's estimates.

Commenters disagreed with analysis in the proposed rule that suggests pipeline infrastructure

c osts would make new NGCC units too costly in many locations and hence disqualify this option as BSER. Commenters compiled a map showing the proximity of most coal

- fired power plants to natural gas infrastructure. Commenters noted that the median miles of p ipeline required per boiler is only 27.1 miles, and by definition half of the coal

- fired boilers in the U.S. are closer, some significantly closer. Commenters noted that EPA's median calculated connection cost is only $20 million, an extremely modest cost compared to conventional pollution control retrofits for coal

- fired power plants, let alone the cost of CCS. Commenters added that the connection costs for half of these coal

- fired boilers would be even less.

Other commenters stated that EPA's estimate of the NGCC capacity that is available to support

re

- dispatch is inaccurate.

Commenters stated that EPA has overestimated available NGCC capacity by relying upon nameplate capacity rather than actual capacity. Commenters said that generators cannot achieve nameplate capacity when operating under real

- world conditions, and are further limited during summer and winter months due to high and low ambient temperatures.

Several commenters also noted operational constraints not included in EPA's estimate of NGCC

ca pacity, including permit limitations (load restrictions, operating hours, total emissions, and incremental consumption), contractual commitments to serve loads in other states or RTOs, and needs for NGCC availability to support existing and new RE

. Comment ers added that NGCCs are best suited to support variable RE because of their quick start

- up times and high ramping capabilities, and that given EPA's predicted increases in RE development under Building Block 3, a substantial amount of NGCC generation must be available to provide peaking and intermediate service.

Commenters also stated that EPA has not considered the time and infrastructure necessary to support re

- dispatch, and specifically noted land acquisition and siting obstacles, transmission capacity, pipeline capacity, facility design and construction, and need for transmission studies. Commenters added that energy providers would be heavily reliant on other entities to develop and build natural gas infrastructure and would be forced to rely on other transmission investors to provide for build

- up of transmission to support the capacity new NGCC plants bring to the grid. Commenters added that emission targets should be delayed because additional pipeline infrastructure must be built before new NGCC unit s can be utilized.

Commenters noted that according to EPA's estimate, NGCC generation would increase more than 50 percent between 2012 and 2020 under the Proposed Rule, which the commenters said would completely transform the country's NGCC fleet from a so urce of intermediate and peaking service into the main source of baseload power

. Commenters said that, given the scope of this transformation, EPA must consider whether the 70 percent target utilization rate is reasonable in light of the significant barriers to widespread re

- dispatch which have been noted.243 Commenters described financial impacts on end users of electricity resulting from shifting energy sources from coal

- fired generation to existing NGCC and RE. Commenters said that it is essential tha t new NGCC and existing peaking gas units count for compliance.

Commenters disagreed with EPA's compliance modeling showing Florida cumulatively adding 3,815 MW of NGCCs by 2018 and 11,219 MW by 2020, which would represent a 33% increase in NGCC capabilit y from 2012 to 2020. Commenters stated that this time schedule is unrealistic due to the time required to site, design, permit, and construct these units.

Commenters also provided extensive comments on the inability to significantly expand electricity gen eration using existing and new NGCCs. Commenters said that there is a significant gap between the amount of energy that can be generated in compliance with the CO2 goals and the amount of energy that must be generated to supply reliable electricity to the population. Commenters said that the EPA recognized this in the NODA when it proposed that a potential means of addressing the wide disparity in CO2 emissions rate goals in states with existing NGCC compared to states without existing NGCC is to artificial ly assign a minimum re

- dispatch to NGCC percentage to states with little or no existing NGCC. Commenters noted that this will force these states to build new NGCC to meet these targets because it will lower the CO2 emissions rate goals in these states whil e raising the goals in states with existing NGCC.

Commenters added that it is unreasonable to decide how much coal generation should be reduced in a state based on how much NGCC generation that state has, and that infrastructure build

- out will be of partic ular significance in states with little or no NGCC capacity. Commenters stated that establishing a minimum floor does not alleviate the disparity between states with sufficient NGCC capacity and those without, and that although a minimum floor would presum ably shift the final emission standards for some, it would not resolve the underlying arbitrary and capricious nature of the standard

. Commenters also noted that a requirement that some states add new NGCC capacity is not consistent with an existing unit s tandard, and that while EPA treats new and existing sources interchangeably, that contravenes the plain language of the statute, further illustrated by EPA's proposal to require a minimum NGCC build

- out in every state.

Commenters said that regardless of w hether it can be used for compliance purposes, utilities will turn to new NGCC to make up the shortfall in base load generation resulting from the proposed rule, and that energy providers must evaluate whether to build NGCC in the state where the affected EGU is located or in a state in which its load is located

. Commenters said that even ignoring effects of the proposed CPP, demand for natural gas is expanding, and additional reliance on NGCC sources may not be feasible considering the natural gas market and infrastructure is already at its edge. Commenters added that without considering the NGCC expansion proposed in the CPP, the Interstate Natural Gas Association of America (INGAA) estimated that the U.S. and Canada will need 28,900 to 61,600 miles of ad ditional natural gas pipelines through 2030. Subsequent to making that estimate, commenters said, the INGAA predicted that just to meet existing and forecasted demand over the next twenty years, the U.S. and Canada need about 850 miles per year of new gas transmission mainline and over 800 miles per year in new laterals to and from power plants and processing facilities. Commenters added that annual costs for completing the necessary natural gas expansion are estimated at $10 billion per year. Given the hig h cost, in addition to the complicated siting and244 permitting processes for natural gas pipeline, and storage and other necessary infrastructure, commenters said that the timeline proposed in the CPP for increasing reliance on NGCC units is unrealistic and too short. Commenters concluded that at a minimum, the EPA needs to re

- think this timeline and extend the long term goal to 2040.

Commenters noted that natural gas units provide diversity to the power grid, with NGCC units following the load of energy thro ughout the day and that employing diverse fuel sources ensures a secure and reliable energy supply. Commenters said that reduced reliance on coal

- fired power combined with increased reliance on NGCC will decrease diversification of fuel sources which will constrain the power grid's ability to respond to unforeseen events such as regional transfers, labor strikes, unplanned outages and abnormal weather conditions.

Comment 2: Commenters said that expanding building block 2 to include new NGCCs as part of the BSER is illegal and/or unsupported under section 111.

Response 2: The EPA has not included new NGCC or any other new fossil fuel

- fired generation in the BSER for this section 111(d) final rule. For the EPA's response to this comment see section V.A and V .B of the final rule preamble of the CPP

. The following are summaries of the specific public comments under this comment:

Multiple commenters said that the EPA has no authority under section 111(d) to impose federally enforceable obligations on new sources or to require the construction of a new source.

Commenters said that constructing a new NGCC unit cannot be considered to be a "system of emission reduction" under section 111. Commenters stated that, if the EPA were to designate new NGCC units as compon ents of BSER for existing units, it would violate the bright

- line distinction between new and existing sources that is a hallmark of section 111

. Commenters added that because new sources cannot be subject to regulation under section 111(d), the EPA
may no t consider the construction of, or emissions from, new EGUs in setting the BSER standard for existing sources. Commenters noted that existing sources are not even subject to regulation until after the EPA has adopted standards for new sources within the sa me source category.

Commenters said that the EPA's contention that "CAA section 111(d) is silent on whether requirements imposed under a CAA section 111(d) plan continue for a source that ceases to be an existing source because it modifies or reconstructs" is inaccurate.

Commenters stated CAA section 111(d) clearly governs "existing sources" which by definition excludes "new sources."

Commenters said that when a source is modified, by definition, it ceases to be an "existing" source subject to section 111 (d) and becomes a "new" source subject to section section 111(b)

.245 Commenters said that new sources must be regulated under section section 111(b) and that the EPA has no discretion to circumvent Congress's clear directive by regulating new sources under section 111(d). In other words, commenters stated, Chevron deference principles to not apply.

Commenters stated that if EPA were to include new NG CC as a component of BSER and include it in state goals, it would in effect be treating that capacity as existing before it is even built.

Commenters said that new units will be subject to EPA's proposed Section section 111(b) standards, and the same unit cannot be regulated under both Section section 111(b) and Section 111(d) at the same time, adding that any decision to go beyond the authority of Section 111(d) and regulate new units should be made at the sole discretion of the State.

Commenters added tha t excluding new units from section 111(d) plans would create an incentive to modernize and build new NGCC capacity that can attain even higher efficiency levels than is achievable with existing units. Commenters said that requiring states to include new un its in existing state plans would increase the legal uncertainty surrounding the rule and discourage investment in new, more efficient capacity. Commenters added that it would not be reasonable for the EPA to attempt to include new NGCC capacity as a compo nent of BSER and include it in state goals because of the tremendous uncertainty regarding new NGCC development.

Commenters noted EPA's proposed rule does not require new units to comply with state plans, but that modified or reconstructed existing units s ubject to implementation plans approved under the proposed 111(d) rule would continue to be subject to CO2 reduction requirements. Commenters added that these units would be required to comply with both the state plan's applicable section 111(d) requiremen ts and the separate federal NSPS for modified/reconstructed units. Commenters stated that EPA appears to be combining the gas and fossil

- fueled EGU categories as a legal prerequisite for treating re

- dispatch from coal

- fired to gas

- fired EGUs as a component of BSER, noting EPA's statement that existing facilities could eliminate their 111(d) implementation plan through modification. Commenters observed that EPA proposes to codify all of the proposed rule's requirements for all affected sources into a single source category under a new subpart UUUU (40 CFR part 60), citing that a single super

- category for all fossil EGUs would facilitate emission trading among sources.

Commenters said that the limit on the EPA's authority (regarding new and existing sources) extends to the EPA's promulgation of emission guidelines for state compliance plans and what sources states may be required to control as part of such plans. Commenters stated that questions regarding how emissions from new sources should be treated in sta tes where the section 111(d) emission standard (i.e., the emission rate defined by EPA as applicable in the state) is lower than the section section 111(b) emissions rate for new sources implies that new sources should be subject to additional controls sin ce their emission rate would be above that which is applied to existing sources generally. However, commenters said that it would be a violation of the statute for the EPA to consider new sources regulated under section section 111(b) for purposes of defin ing what emission rate would apply in a state under section 111(d), or for EPA to expand the scope of sources that would be subject to an section 111(d) emission rate or other control in a state plan. Commenters added that any interpretation that required new source emissions to be counted towards compliance would needlessly constrain a state's flexibility to meet increased electricity demand in the most cost

- effective manner.246 Commenters stated that EPA should not require that new NGCC units be included in 111(d), because a source cannot be both new and existing under section 111. Commenters noted that in the proposal for modified or reconstructed sources, EPA states that existing sources subject to a section 111(d) plan that later modify or reconstruct rema in subject to the 111(d) plan while becoming subject to the modified/reconstructed standard. Commenters pointed out that this makes a source both new and existing, which is not allowed under the governing statutory framework, and furthermore that a rule fo r modifications / reconstructions cannot serve as the necessary predicate for another rule when the former rule is invalid. Commenters said that states need to have the flexibility to choose which sources will be included in their section 111(d) plans beca use once they are included, removing certain sources may prevent a state from meeting its target rate plan obligations. Commenters added that once a source becomes subject to the 111(d) plan, states should be allowed to continue to include that source with in the plan, and EPA should be indifferent to this outcome, provided state target rates for CO2 are being met.

Commenters supported the EPA's proposal (79 FR 34877) to exclude new NGCC capacity as a component of BSER for BB2 and therefore exclude such capa city in establishing state goals. Commenters agreed with the EPA (79 FR 34904) that new NGCC capacity will be regulated under section section 111(b) and the EPA cannot simultaneously treat the same capacity as an existing unit under section 111(d)

. Comment ers stated given the fact that the EPA does not propose to include this option in state goals because it believes the cost considerations indicate a higher cost for CO2 reductions achievable from re

- dispatch to new NGCC capacity than for other options (79 FR 34877), commenters did not see how the EPA could then justify disregarding that finding and including new NGCC capacity as a BSER component

. Commenters stated that a "system of emission reduction" is limited to activities that can be implemented at th e source itself or within the source category, and may not include beyond

- the

unit measures. Commenters added that the approach the EPA discusses would require owners to go beyond the source itself and construct an entirely new source to replace it. Comme nters added that the EPA's claim that a source owner "may invest in new NGCC units," does not mean that replacing an affected EGU's generation with generation from a new facility can be required under CAA section 111.

Commenters stated the EPA should not i ncorporate natural gas co

- firing or re

- dispatch to new NGCCs into state goals because these measures do not constitute BSER. Commenters stated that designating co

- firing as BSER would effectively redefine the source by recasting coal

- fired EGUs as EGUs tha t are capable of burning large amounts of natural gas. Commenters stated the EPA cannot simply redefine an entire source category when establishing emission standards for that category.

Commenters said including new NGCC units as part of BSER for existing units is not defensible since they are already subject to section 111(b) and "outside the fence line" of the existing units, and that they fear that EPA's proposed action could create regulatory uncertainty when it is challenged in court. Commenters said that States would be placed in a predicament of having to comply with a plan, while the basis of that compliance requirement would be uncertain. Commenters requested that EPA incorporate additional time into the compliance schedule for such legal issues to be resolved.247 Commenters added that the CAA does not contemplate shifting generation between types of EGUs in setting a BSER requirement as the EPA proposes in building block 2. Commenters said that this is beyond the bounds set by the CAA, as BSER should reflect what is achievable and
cost

- effective for each specific source category and does not contemplate setting emission limits across different types of EGUs in the whole generation system. Also, commenters said, expanding the shift to natural gas gener ation beyond the use of NGCC "to include fuel switching from coal to natural gas fuels directly at the steam boilers" is beyond the EPA's authority under the CAA, as BSER should not dictate the use of fuels or the capacity factor of an EGU in any

manner.

C ommenters said that the proposed CPP is unclear about how newly constructed NGCC may be used as part of a state compliance plan and requested clarification to give regulatory and planning certainty

. Commenters stated that State plans are not limited to me asures EPA has defined as BSER (including new NGCC units), and noted that other EPA regulatory programs allow states to build new NGCC units to comply with CAA standards and air quality goals. Commenters stated that regulations under section 111(d) should be no different

. Commenters stated that new NGCC units which are subject the standards EPA proposed under section section 111(b) , and used as compliance tools should not change their regulatory status, and noted that EPA has not articulated any policy or legal rationale for regulating these units simultaneously under both CAA subsections section 111(b) and 111(d). Commenters added that EPA's final guidelines must clearly state that units built after proposal of the new source CO2 emission standards which a re in compliance with those standards will not become section 111(d) units at some point in the future. Commenters noted that State compliance plans submitted in 2016 will be designed
to achieve the 2030 goal calculated by EPA relative to the 2012 emissio n rate, and that it would be inconsistent and unfair if EPA changed the goals after compliance plans are approved to address new NGCC units built after January 8, 2014. Commenters stated that this would undermine both state flexibility to use these units for compliance purposes and the certainty states and utilities need with respect to the final goals so that they confidently can invest resources to achieve them.

Commenters stated that, regarding EPA's request for comment on whether they should consider

c onstruction and use of new NGCC capacity as part of the basis supporting the BSER and on ways to define appropriate state

- level goals based on consideration of new NGCC capacity, EPA does not have the authority to combine these statutorily separated progra ms, given that the statute states that an existing source means any stationary source other than a new source. Commenters stated that this would, in effect, create a statewide cap on the state CO2 emission rate and bringing new gas units into the existing unit program would radically change section 111 and the entire existing unit program as to its nature, reach and stringency with huge policy, feasibility and cost implications, creating a nationwide cap on CO2 emissions from fossil EGUs. Commenters stated that section 111(d) applies to existing units only.

Comment 3: Commenters urged that new NGCC should be identified as an "affected facility."248 Response 3: New NGCC units are subject to the standards set for new sources in the section section 111(b) final rule. They are not affected EGUs under this section 111(d) final rule. For the EPA's response to this comment see sections V.A and VII.D of the final rule preamble of the CPP

. The following are summaries of the specific public comments under this c omment:

Commenters said that the CPP should provide states and companies the flexibility to rely on actual emission rate improvements caused by construction of new lower

- intensity carbon units. In contrast, commenters said, the EPA's proposed rule explicit ly excludes section section 111(b) sources from the definition of affected entity, which disincentivizes both the replacement of existing coal

- fired EGUs with new NGCC units and the addition of new NGCC units to meet future demand in states that opt to uti lize rate

- based goals.

Similar to the EPA's proposal to use modified or reconstruction units (units otherwise subject to section section 111(b) standards) as compliance mechanisms for section 111(d) plans, commenters said that the EPA should allow new NGC C subject to regulation under section section 111(b) to function as compliance sources under section 111(d)

. Commenters said to accomplish this, The EPA should specifically include new NGCC as a unique type of affected entity and allow states to use new NG CC as a compliance mechanism both for affected EGUs (by allowing the substitution of CO 2 emission rates from retired or lesser

- utilized coal

- fired EGUs with lower rates from new NGCC capacity) and to meet or maintain state emission rate goals if additional capacity is need for future demand. Commenters stated that the EPA has the option to determine whether this would specifically impact BSER for affected EGUs. Commenters noted that in BB2, increased utilization of NGCC units, the EPA recognized the CO 2 red uction benefits that could be realized through construction of new NGCC and that it makes sense to use natural gas to generate electricity at a different affected EGU with a better heat rate (i.e., a NGCC) and to substitute that electricity for electricity from the coal

- fired steam EGU

. Commenters said that to effectuate this goal of improving heat rate and reducing utilization of higher

- emitting existing EGUs The EPA must specifically recognize new NGCC under the proposed rule as eligible to constitute an affected entity. Commenters agreed with other commenters who noted that the increased utilization of NGCC units will naturally factor into compliance in states with mass

- based goals and that states using rate

- based performance goals should not be disadvant aged by the unusual math problem created by the difference between mass

- or rate

- based performance goals. However, commenters did not believe that the rule as proposed will create the necessary incentives to add new NGCC capacity to reduce CO 2 emissions.

While increasing the proportion of fossil

- fuel generation to NGCC EGUs with lower CO 2 emission rates may reduce (or proportionally lessen any increase to meet higher demand) state

wide mass CO 2 emissions, commenters said that unless all states are permitte d by rule the option of accounting for new NGCC will have little to no impact on state average CO 2 emission rates. Commenters added that many states will chose to adopt a rate

- based approach, and most new NGCC will not be constructed until after the CPP i s effective such that the majority of new NGCC will not be a factor towards achieving compliance with the CPP. Commenters provided examples of the challenges of incentivizing New NGCC in states with rate

- based compliance goals. Commenters said that designa ting new NGCC as an affected entity under the proposed249 rule would not conflict with the exception under section 60.5800, which applies only to affected EGUs. Commenters said that state plans must establish "standards of performance" for affected EGUs, and the use of new NGCC as a means for a state to achieve its performance standards at its affected EGUs is consistent with this requirement.

Commenters did not propose that the EPA designate a new NGCC as an affected EGU

. Commenters said that by limiting the applicability of new NGCC to affected entities, the new units act merely as a compliance mechanism for the state to achieve its rate

- based goal for purposes of section 111(d), and the new NGCC would still need to meet a ll applicable requirements under CAA section section 111(b) . Commenters said that subjecting new EGUs to the requirements of both sections section 111(b) and 111(d) is consistent with the EPA's proposed handling of modified or reconstructed sources under t he proposed rule and noted that existing units that are modified or reconstructed constitute "new units" under section 111(a) and are subject to the regulatory requirements under section section 111(b) , much like a greenfield unit. However, commenters stat ed that as proposed, modified or reconstructed existing sources would remain subject to The state's section 111(d) plan largely to "assure the integrity of the CAA section 111(d) plan." Commenters said that the same logic should apply to new NGCC
construct ed to replace existing coal

- fired units subject to a state's 111(d) plan or to add capacity and lessen the overall proportion of state generation from higher

- emitting coal

- fired units

. Commenters said that to hold "new" units modified or reconstructed to b urn natural gas as eligible compliance mechanisms for a section 111(d) plan but not "new," more efficient, NGCC units is to find a distinction without a practical difference

. Commenters said that in states with
rate

- based goals, the addition of new NGCC is a reasonable and effective compliance mechanism to reduce CO 2 emission rates while ensuring that those states have sufficient capacity to meet expected increases in demand

. Commenters said that without the ability under a state's 111(d) plan to account fo r emission rate reductions from new NGCC, the rule as proposed jeopardizes the integrity of any existing rate

- based plan by ignoring the benefit of increasing the proportion of low

- emitting NGCC units.

Comment 4: Commenters addressed proper treatment o f "under construction" NGCC plants.

Response 4: EPA has determined that construction of Carty commenced on January 9, 2014, when site work began and, therefore, the facility is subject to the New Source Performance Standard (NSPS) 40 C.F.R. Part 60, Subpa rt KKKK (Subpart KKKK) CO2 standard for new combined

- cycle natural gas

- fired stationary combustion turbines.

The following are summaries of the specific public comments under this comment:

Commenters stated that the Portland General Electric Company (PGE) is currently constructing the Carty Generating Station near Boardman, Oregon and noted that the EPA excluded Carty from the process of establishing Oregon's state goal. Commenters said that Carty is a section 111(b) resource and not a 111(d) resource and t hat the EPA presumably excluded Carty from the establishment of Oregon's CPP goals because it agrees with this classification. However, commenters explained that the EPA has not yet responded to a determination request filed pursuant to Section section 111 (b) and that it must do so prior to finalizing Oregon's CPP goal. If250 EPA determines that Carty is a 111(d) resource, commenters said that Carty must be treated as an under

- construction resource and its emissions and generation should factor into Oregon's g oal.

Commenters said that the subpart KKK NSPS apply to new sources that "commence construction" after January 8, 2014. Commenters added that the NSPS General Provisions define construction as having "commenced" as follows:

Commenced means, with respect to the definition of new source in Section 111(a)(2) of the Act, that an owner or operator has undertaken a continuous program of construction or modification or that an owner or operator has entered into a contractual obligation to undertake and complete,

w ithin a reasonable time, a continuous program of construction or modification.

Under this definition, commenters said, commencement of construction occurs either upon commencement of site work (i.e., a continuous program of construction) or the date that t he owner enters into a contractual obligation to construct the affected facility within a reasonable time. Commenters concluded that the decision as to which of the two events to rely upon to determine when construction commenced is left to the source. In the case of Carty, commenters said that PGE concluded that the appropriate event for determining the date that construction of Carty commenced is the date that site work began, i.e., January 9, 2014.

Commenters recognized that they might have the ability to avoid the CO2 standards under Subpart KKKK by choosing instead to define the "commence construction" date based on the date the company entered into a contractual commitment to complete construction of Carty within a reasonable time period. However, com menters said that PGE prefers to employ the later date, establish Carty as a new source and comply with the CO2 standards in subpart KKKK because this enables greater clarity in identifying applicable requirements.

Commenters said that on September 9, 2014 , PGE's outside counsel (Stoel Rives, LLP) sent a letter to Heather Valdez at EPA Region 10 asking for clarification on their determination that Carty is a section 111(b) resource subject to NSPS CO2 standards. Commenters urged the EPA to provide this clar ification as soon as possible, and believed that the EPA's proposed approach to exclude Carty from the calculation of Oregon's state goal is appropriate, provided it is not determined to be a 111(d) resource. If the EPA determines that Carty is among the r esources that must comply with the CPP, commenters said that the EPA must include Carty's generation and emissions in setting Oregon's goal as it has for "under construction" NGCCs in other states.

Comment 5: Opposition to new NGCC with regard to renewabl e energy. Including emission leakage concerns.

Response 5: The EPA is taking steps to address emission leakage concerns regarding generation shifting to new NGCC and other non

- affected units

. For the EPA's discussion of new NGCC units, see section V.A of t he final rule preamble of the CPP . Leakage from non

- affected units is discussed in preamble section VII.D and VIII.J.

The following are summaries of the specific public comments under this comment:251 Commenters said that the EPA should not promote the construction of new NGCCs because it will discourage renewable energy

. Commenters said that creating new NGCC units will increase the pressure for their continued future utilization, discourage renewable energy generation, and thus result in additional gre enhouse gas emissions in the long run. Commenters also noted disincentives for utilities to reinvest in renewables since they have already made large capital outlays for gas infrastructure. Commenters said that additional renewable energy infrastructure sh ould be built, and EE measures increased more quickly, so that additional fossil

- fuel infrastructure build

- up is avoided.

Commenters added that an incremental shift from coal

- fired EGUs to new NGCCs will not reduce emissions because EPA has not required si gnificant improvements for newly constructed, modified or reconstructed NGCCs. Commenters noted that highly efficient NGCCs emit much less CO2 than EPA's proposed standard for these units, which therefore do not constitute BSER under section section 111(b) . Commenters added that construction of new but low

- efficiency NGCCs may slightly reduce emissions compared to displaced coal

- fired EGUs, but would increase emissions compared to efficient NGCCs and renewable source generation and perpetuate use of these s ources, which undermines EPA's stated goal to achieve meaningful CO2 emission reductions and the D.C. Circuit's directives to consider actual emission reductions and avoid creating further problems when designing BSER. Commenters stated that although state s may choose measures outside of the Proposed Rule to reduce their emissions, it is one thing for a state left without other choices to resort to building new NGCC plants, but another thing entirely for EPA to integrate this possibility into BSER for the n ation and its emissions targets. Commenters said EPA must apply far more stringent new source performance standards to newly constructed, modified and reconstructed units under section section 111(b) so that whatever new units are constructed will at least be the most efficient units feasible.

Comment 6: Commenters supported including new NGCCs in BSER in part because it is needed to ensure symmetry between goal setting and compliance.

Response 6: New NGCC is not included in the BSER and is not an allowab le measure for adjusting EGU emission rates in rate

- based state plans. For the EPA's response to this comment see sections V.A regarding the BSER, and VIII.J and VIII.K regarding compliance flexibilities in the final rule preamble of the CPP

. The following are summaries of the specific public comments under this comment:

In response to the EPA request for comment on whether the BSER should also reflect potential reductions in emissions from affected sources because of a shift in dispatch to new NGCCs, as

we ll as opportunities to reduce the carbon

- intensity of coal

- fired EGUs through co

- firing or repowering with natural gas, commenters agreed that it is feasible to rely on NGCC construction in Building Block 2.

Commenters noted that 119 GW of new NGCC plants have been constructed over the 10

- year period from 2003 to 2012 (EIA), which confirms that it is reasonable to anticipate a continued rate of expansion of this well

- understood technology. Commenters said that this conclusion is252 affirmed by the IPM complia nce modeling of the Clean Power Plan conducted by EPA, which showed that "construction and operation of new NGCC capacity will be undertaken as a method of responding to the proposal's requirements." Commenters stated the IPM model results also affirm that the costs of new NGCC are reasonable. Commenters said that the IPM model seeks to satisfy each state's target rate through the least expensive method and the fact that the model selected new NGCC (even though NGCC was not included to set the targets) demo nstrates that the costs of such plants are reasonable. Also, commenters stated, financial analysts such as Lazard have determined that new NGCC is one of the lower cost generation resources available to power companies today, as shown in the figure 3, Comp arison of Unsubsidized Levelized Costs of Energy Generation. Commenters described a number of utilities have retired coal

- fired power plants and replaced the generation capacity with new NGCC units in recent years and, following the proposal of the Clean P ower Plan, additional coal

- to

- new

- NGCC replacement plans have been announced.

Commenters noted that a shift in dispatch to new NGCC units has been a significant component of the system the Clean Power Plan Implementation Group states have used to achieve emission reductions and emission intensity improvements. Commenters stated that between 2005 and 2012

- the same period that those states saw significant decreases in coal

- fired electricity generation, decreases in CO2 emissions, and improvements in emiss ion rates

- those states experienced a collective increase of 12,584 megawatts of NGCC nameplate capacity. Commenters indicated that in 2012, NGCC units that began operation after 2005 contributed an additional 50 million megawatt hours of generation. Comm enters also stated that a number of coal

- fired EGUs in those states have already reduced their carbon pollution rate by co

- firing with natural gas which demonstrates that in some circumstances, such strategies are cost

- effective under current market condit ions.

Commenters also pointed out that within the group of states participating in RGGI, the overall shift in generation from carbon

- intensive EGUs to more efficient and less carbon

- intensive NGCC units is at least partially attributable to the emission b udget trading program. Commenters indicated that since the program sets a price on carbon emissions through the auction of emission allowances, NGCC units incur lower emission allowance costs relative to coal

- fired generation units and therefore are called on to operate more often. Commenters noted that there are other examples of state programs that have promoted a shift to NGCC generation and the resulting reduction in CO2 emissions:

• In Delaware, energy providers NRG and Calpine have used a state grant p rogram to replace coal

- fired generation units with combined cycle natural gas plants; the state now has only one remaining coal

- fired generating unit. Delaware reduced carbon pollution from the power sector by over 27 percent from 2005 to 2012, while incre asing natural gas generation by over 300 percent and decreasing coal generation by 70 percent.

• California's in

- state fossil generation is almost entirely natural gas

- fired, and the state is rapidly phasing out imported power from higher

- emitting coal

- fire d power plants through implementation of an Emissions Performance Standard. These coal imports represent only about 7.5 percent of California's energy portfolio, and are expected to continue to decline through 2020.253 Commenters said that treatment of new NG CC for target setting and compliance must be symmetrical. Commenters described BSER principles and stated that the technical and economic feasibility of an emission limit is linked to the methods available for demonstrating compliance. (See, e.g., Portland Cement Association v. Ruckelshaus. 486 F.2d 375. 396 (D.C. Cir. 1973) (measurements relied on to demonstrate achievability may have "deviate[d] from procedures, outlined by regulation, for ascertaining compliance with prescribed standards") If a guideline allows compliance through a given method of reducing emissions, and that method is a superior system of emission reduction or would be part of a superior system of emission reduction, commenters said that the EPA must consider that compliance method when determining the level of reductions that the standard of performance or target requires. Commenters said that it would be a deviation from the statute for the EPA to set a target based on a reasonably foreseeable emission reduction technique but not allow that technique to be used for compliance purposes. Likewise, commenters added, it would be a deviation from the statute to allow the use of a reasonably foreseeable emission reduction technique for compliance purposes but exclude it from consideration when setting the target, particularly when that emission reduction technique is expected under the Agency's own analysis (79 FR at 34,876) to play a significant role in compliance.

Commenters said that, given existing market trends and the Agency's own analysi s of possible compliance scenarios, it is reasonable to project the construction of certain amounts of new NGCC capacity; such capacity must reasonably be considered adequately demonstrated at a reasonable cost. Commenters said that the emissions limit in the guideline must reflect the emission reductions that can be achieved through the use of such new NGCC plants. Commenters added that the EPA's initial proposed rule that might have excluded new NGCC plants from the determination of the targets but would have allowed them to be used to generate credits is asymmetrical and is not permitted. Similarly, if the EPA were to exclude a new NGCC capacity from target

- setting but allow it to be used for compliance, commenters said that the standard would under

- repre sent the degree of reduction achievable at reasonable cost. Commenters added that the EPA's own IPM compliance modeling runs assumed new NGCC capacity would count for compliance, even though it was not taken into account when calculating building block 2.

Commenters also said that the fact that new NGCC plants are subject to standards of performance under section section 111(b) does not prevent the EPA from considering their emission reduction potential when establishing targets under section 111(d). Comme nters stated that new NGCC capacity would not be regulated under section 111(d) any more than new renewable capacity. Commenters stated the EPA would simply consider the potential for existing coal

- fired EGUs to cost

- effectively acquire credits derived fro m either source (new NGCC or new renewables) in determining the target appropriate for such EGUs. Commenters stated that the EPA' proposal simply requires that new NGCCs be treated like new renewables or new efficiency: all three are sources of megawatt ho urs with emissions rates lower than coal plants (or old gas plants) that they would displace, and this does not mean that a section 111(b) source is placed under a 111(d) obligation. Under the EPA's proposal, commenters said, the agency considers generatio n created (or avoided) by new renewables, efficiency, and nuclear in its BSER determination but does not propose to make them regulated facilities under 111(d). Commenters concluded that the EPA can apply the same approach to new NGCC plants, which would remain subject only to section section 111(b)

.254 Commenters said EPA must undertake a more granular analysis of the ability of 'inside the fence' new NGCC to arrive at a more legally defensible BSER. Commenters believed new NGCC presents a particularly compe lling compliance option because it can make use of existing transmission infrastructure and be built on the existing sites of coal

- fired power plants. Furthermore, commenters asserted that new NGCC is a less expensive abatement measure on a CO 2 $/ton basis than some renewable generation sources. Commenters added that new NGCC plants, including those 'outside the fence', represent a significant opportunity to reduce GHG emissions. Commenters concluded that shifting from higher

- emitting to lower

- emitting sour ces is a reasonable alternative approach barring extraordinary costs or other state

- specific issues. Commenters supported all three proposed options as components of BSER provided they are onsite and can be undertaken at existing sources.

Commenters stated that the EPA has failed to provide quantitative support for its decision to exclude new NGCCs from the BSER determination and state goal calculation methodology. Commenters stated EPA assumes that the additional demand for natural gas would result in high er natural gas prices and that new NGCC units would entail higher capital investment and pipeline infrastructure costs. However, commenters said review of the CPP proposal, GHG Abatement Options TSD and draft RIA did not reveal the EPA's quantitative basis for these conclusions. Commenters stated the only mention of new NGCC costs The y could find in the documents supporting the CPP proposal is the following statement: "For example, EPA analysis indicates that replacing the coal steam plant discussed above w ith a new NGCC facility would reduce the net CO 2 emission rate of the generating capacity by 62% at a cost of about $50/tonne of avoided CO 2 under the base case projected gas price and about $81/tonne of avoided CO 2 at a future gas price 50% higher than the base case projection. See preamble section VI.C.3.c."

Commenters stated there is no economic information in preamble section VI.C.3.c or other documents that support this conclusion. Commenters added that if the EPA is concerned about the use of new NGCCs putting additional upward pressure on natural gas prices or higher infrastructure costs, it should refer to the IPM modeling to see that new NGCCs are predicted to be part of state compliance with the CPP without causing undue gas price or infrastructure cost impacts. In addition, commenters asserted the NorthBridge analysis of their Power Switch idea shows new NGCC capacity coming online to replace coal units that retire as a result of the CPP, finding that this will occur (including associated capital and gas pipeline infrastructure costs) without any significant increase in gas prices or other economic impacts, and at a marginal cost of compliance far lower than the Social Cost of Carbon.

Commenters added that all of the new NGCC units that have been announced or that the modeling analyses predict will be built after 2012 are "new" the day the come online. Commenters added that the EPA's own analysis of the BB2 gas redispatch strategy itself provides support for more explicitly including new NGCCs in the state goal calculation. If the EPA continues to have concerns about the gas price, capital and infrastructure cost impacts of broad inclusion of new NGCC, commenters said that the EPA could direct states in their target setting to include new NGCC only in the states has little or no potential for natural gas redispatch from existing NGCC units. Commenters said this would mitigate overall costs and pressure on gas prices while the stringency of those state targets could be increased and disparities mitigated between states that received relatively more stringent targets due to their greater existing NGCC redispatch potential and those with less potential.255 Commenters believed BSER must include new NGCC at existing po wer plants; over 20 GW of new NGCC plants have been proposed or already sited at the locations of decommissioned coal plants and EPA should take this trend into account.

Commenters said that the EPA should consider revising building block two to achieve the potential for re

- dispatch from existing coal EGUs to new NGCC plants likely to be constructed between now and 2030. Commenters stated this significant new capacity repr esents the potential for additional reductions not contemplated by the proposal, especially by states not currently subjected to this building block due to their lack of existing NGCC plants. Commenters said that the new capacity dampens the compliance cos ts attributable to the CPP and that the experience of the RGGI states illustrates that it is reasonable and consistent with demonstrated practices to contemplate the potential for additional re

- dispatch to lower

- emitting EGUs as part of the target

setting methodology.

Commenters suggested that in evaluating a state's potential for new NGCC capacity, the EPA could derive a target using the national compound average growth rate for natural gas projected by the U.S. EIA's Annual Energy Outlook, or some other uniform national standard. Commenters said that other considerations could be the production capacity and construction plans for new natural gas pipelines, as well as the potential to re

- power existing coal boilers. As with all of the building block method ologies, commenters added, the states would not be limited in their compliance options and could achieve the targeted emission reductions through any low

or zero

- emitting technology, should that option prove more competitive in the particular state.

Comme nters expressed concern that new fossil fuel generation is not required to be included in the compliance calculation, although it is allowed as a compliance option

. Commenters added that EPA should establish a consistent method to consider new generation i n the compliance calculation, and to the extent that the availability of new generation provides additional credit at lower compliance costs, EPA should consider setting more stringent targets. Commenters stated that this is important because EPA's plan pr ojects that Pennsylvania will redispatch 8.7 million megawatt hours (mWh) of coal generation to other forms of generation, while recent reports by PJM project over 15 million mWh of coal capacity in PA has either retired since the 2012 baseline or announce d plans to retire

. Commenters stated that since existing NGCC units in Pennsylvania would need to exceed a 70 percent capacity factor to take on this load, it is clear that new NGCC units are likely to be implemented, and noted that there is currently over 8 GW of gas capacity currently in the Pennsylvania portion of PJM's active generation queue.

Commenters said that utilization of NGCC in New Jersey beyond the goal setting capacity factor of 44% could actually move New Jersey further away from goal compli ance (depending upon how EPA accounts for NGCC) and, as a practical matter, adding new NGCC units may not be a viable option for New Jersey to pursue, even though adding NGCC would advance EPA's overarching national emissions reduction goal by displacing h igher emitting sources. Commenters noted that, according to the EPA's Technical Support Document: Goal Computation, the national average emission rate for all affected NGCC units is 908 lb/MWh. If the EPA adopted a uniform national performance goal of 1,03 0 lb/MWh, commenters said that it would allow ALL states to use their existing NGCC fleet as a compliance option and not just the states with goals higher than 908 lb/MWh.256 Comment 7: The use of new NGCC units to displace coal generation and reduce emissio ns is "adequately demonstrated"

Response 7: New NGCC is not included in the BSER and is not an allowable measure for adjusting EGU emission rates in rate

- based state plans. New fossil fuel

- fired units are covered under the CAA section section 111(b) rule for new source performance standards. EPA is requiring states with mass

- based goals to address concerns regarding the shifting of generation and emissions from affected to non

- affected sources (i.e. leakage) in their state plans and is providing several pa thways for them to follow, if they choose to include new NGCC units. For the EPA's response to this comment and discussions of emission leakage, see section V.A, VII.D and VIII.J of the final rule preamble of the CPP

. The following are summaries of the spe cific public comments under this comment:

Commenters said that the EPA should include new NGCC units in BB3 to the extent that they are now under construction, have been publicly announced or needed to replace coal

- fired power plants shuttered as of state CPP plan submission. In addition, commenters recommended that the EPA include in BB3 all the new NGCC capacity needed to replace the coal unit retirements that have been publicly announced as of the date of the final rule. Commenters added that the buildin g block should explicitly include new NGCC on the compliance side through a mass

based allowance trading system. Commenters stated that the use of new NGCC units to displace coal generation and reduce emissions is "adequately demonstrated" by recent electr ic sector experience and forecast system response to the market and regulatory environment. Commenters stated The EPA's IPM compliance modeling also shows that NGCC units constructed after 2012 come online and run, displacing existing coal generation and r esulting in reduced carbon dioxide emissions. Commenters stated that the NorthBridge modeling of CATF's Power Switch proposal predicts that new NGCC units will replace coal capacity retirements resulting from the combination of lower natural gas prices and existing EPA regulations (for example, the MATS rule), as well as those retirements predicted to occur for compliance with the CPP. Commenters said that the NorthBridge analysis found that these new NGCC units come online to replace the lost coal generati on, lowering overall electric system emissions. Commenters added that the retired coal units ran at utilization rates less than 50% annually, and these least economically viable coal units are the most vulnerable to retirement. Commenters stated that new N GCC units coming online to replace this coal capacity have substantial headroom to reach higher utilization rates and displace the generation from existing coal units that are not predicted to retire. Commenters concluded that this incremental gas redispat ch effect from the new NGCCs presents the opportunity for additional, cost

- effective CO 2 reductions from affected coal units.

Commenters said that going forward, particularly in markets where coal units would otherwise run on the margin, new NGCC units th at come online will have the same displacement effect. Thus, commenters stated, the use of new NGCC units to displace existing coal generation and provide coal unit CO 2 emissions is clearly "adequately demonstrated" as a CO 2 reduction strategy, and the EPA has a reasonable basis to include it in determining the BSER and in the state goal calculation as a cost

- effective mechanism to reduce CO 2 emissions. Commenters said that states should therefore evaluate (in their state goa ls) the emission reductions predicted due to257 under construction and publicly announced new NGCC as of the date when they submit its CPP plans. Commenters agreed with the EPA's assertion that replacing fossil steam generation with new NGCCs is "adequately d emonstrated."

Commenters stated that, prior to 2008, electricity produced by coal

- fired power plants supplied nearly half of the electricity produced in the U.S. while natural gas

- fired generation supplied only 21% (citing EIA data) Since 2008, commenters said, the percentage of electricity produced by coal has declined while natural gas generation has risen, and this trend has been driven by two factors: (1) the rapid addition of NGCCs to the power supply since the year 2000; and (2) the availability of c heaper natural gas. Commenters provided Figure 23 which illustrates the large amount of added natural gas capacity since the year 2000. Commenters added that this increased NGCC generation has largely come from the fleet of new, more efficient NGCCs that c ame online during this period. Commenters cited EIA data that show that increased natural gas unit generation has displaced coal unit generation and, as a result of these factors, since 2008, CO 2 pollution from the power sector has fallen sharply. Commente rs commented generally that they favor the construction of new NGCC capacity for BSER.

Comment 8: Commenters said that new NGCC should be included in the goal computation and/or compliance demonstration to avoid adverse effects of this construction.

Respo nse 8: New NGCC units are not included in the goal computation nor compliance demonstration (for states with a rate

- based emission performance standard). For the EPA's response to this comment see sections V.A, and VII.D of the final rule preamble of the C PP

. New NGCC units are not allowed to be used to adjust CO2 emission rates at affected EGUs in state plans under a rate

- based emission standard approach. Permitting new NGCC generation to qualify for ERCs would provide an incentive to shift generation from affected to non

- affected sources (i.e., leakage). Section VII.D and VIII.K.

In mass

- based states, there is a requirement for state plans to demonstrate how the state is going to address concerns regarding potential increased emissions from new NGCC units as a result of shifting generation from affected to non

- affected sources (i.e., Leakage). The EPA is giving

mass

- based states several pathways to address new sources and potential leakage

. Section VII.D and VIII.J.

The following are summaries of the specif ic public comments under this comment:

Commenters said that including the potential for development and use of new NGCCs in BB3 will ensure that the effectiveness of the EPA's proposal is not diluted by the construction of new NGCCs. Commenters added that the proposal contemplates the use of new NGCCs as a compliance strategy but does not quantify the result because new NGCCs are not included in the goal calculation methodology. To maintain the environmental efficacy of the rule, commenters said, the EPA mu st direct states to account for the CO 2 emissions of new NGCCs as part of state compliance demonstrations whether under mass

- based or rate

- based system. Commenters were concerned that, without this adjustment to BB3, the CPP may create perverse incentives to build unnecessary new NGCC units. Because new units are not now subject to the CPP, commenters258 said that a state could achieve emission reductions from affected sources by reducing corresponding generation and constructing new plants to serve the remain ing load without counting the emissions from the new NGCC. Commenters added that simply including new NGCC in the state goal calculation methodology alone may not be sufficient to mitigate this perverse effect if states opt to comply through a mass

- based b udget limited to existing fossil units only. Commenters said that such a structure would also create perverse incentives to build new NGCCs (which would not be under the state budget) rather than utilize existing NGCC (that would) by placing a regulatory " price" on existing NGCC units when none would exist for new NGCC. Commenters concluded that such an approach may reduce the emissions intensity of affected sources in a state without any overall reduction in fleet

- wide emissions, and emissions may simply s hift from existing sources to new sources without any overall environmental benefit, a particularly troubling outcome as new NGCC units can remain in operation for a half

century or more.
Commenters said that the current structure of the CPP may create per verse incentives to build unnecessary new NGCC units. Commenters explained that because new units are not subject to the CPP, a state could achieve emission reductions from affected sources by reducing corresponding generation and constructing new plants t o serve the remaining load which may reduce the emissions intensity of affected sources without any overall reduction in fleet

- wide emissions. Commenters requested that the EPA consider incorporating the potential for new natural gas

- fired units into the t arget

- setting methodology included in the final rule to facilitate the overall goal of reducing emissions and encouraging the development of additional renewable energy resources and energy efficiency programs. Commenters added that allowing states to

coun t new NGCC towards compliance with a target that does not consider the potential for new natural gas creates inequity in the proposal, since many states with relatively low existing and target emission rates would not actually have that opportunity. Commen ters added that the RGGI states have an existing regional emission rate, as well as a 2030 regional emission target, less than that of a typical new NGCC unit.

Commenters added that including new NGCC in the goal computation methodology would reduce dispar ities in the proposed state targets and would help to ensure that the potential for additional cost

- effective emission reduction measures are reasonably reflected in states' targets. Commenters supported consistency between target

- setting and compliance to ols in order to maintain the integrity and effectiveness of the overall program. Commenters said that this methodological adjustment is particularly important for states that are not currently subject to the application of Building Block Two due to a lack of existing NGCC capacity, because absent this consistency the current structure of the CPP may create perverse incentives to build unnecessary new NGCC units. Including the potential for new NGCC capacity can reduce the cost of compliance attributable to the CPP, commenters said, as well as the potential for shifts in generation from existing sources to new fossil fuel

- fired EGUs that do not result in net CO2 emission reductions.

Regarding the use of NGCC for compliance, commenters stated that to ensure s ymmetry between the resources available for compliance and the resources used to determine the targets, unless a potential compliance option is too costly or not adequately demonstrated, it must be included in setting the target if EPA will allow its use f or compliance purposes259 Comment 9: Commenters said that new NGCC units should not be included in goal setting.

Response 9: New NGCC units are not included in the BSER and are not used for goal

- setting. For the EPA's response to this comment see section V.A of the final rule preamble of the CPP

. New NGCC units are not allowed to be used to adjust CO2 emission rates at affected EGUs in state plans under a rate

- based emission standard approach. Permitting new NGCC generation to qualify for ERCs would provide a n incentive to shift generation from affected to non

- affected sources (i.e., leakage). Section VII.D and VIII.K.

In mass

- based states, there is a requirement for state plans to demonstrate how the state is going to address concerns regarding potential incr eased emissions from new NGCC units as a result of shifting generation from affected to non

- affected sources (i.e., Leakage). The EPA is giving

mass

- based states several pathways to address new sources and potential leakage

. Section VII.D and VIII.J.

The E PA is not exempting affected EGUs regardless of when or where they were built.

The following are summaries of the specific public comments under this comment:

Some commenters opposed any consideration of new NGCCs which are not affected sources subject to this rule as part of determining the stringency of BB2. Commenters did not believe the EPA should define appropriate state

- level goals based on consideration of new NGCC capacity. Commenters added that new NGCC also should not be used to offset the growth opportunities that may be afforded in BB 3 and 4.

Commenters stated the current plan is already overly complex and adding forecasted NGCC capacity creates yet another layer of complexity. Commenters said that including these measures into state goal calculations is unlawful and increases uncertainty and p otential for errors.

Commenters said that the development of new NGCCs is impossible to accurately project. Commenters said that new NGCCs (and under construction NGCCs) and co

- firing should be available for compliance but not included in goal

- setting. Co mmenters noted that the CAA delineates separate regulatory requirements for new and existing units and that requiring states to include new section 111(b) units as part of the BSER for existing 111(d) units is inconsistent with the statute.

Commenters said that rather than attempting to stipulate conditions that would force a state to deploy a new NGCC unit or other energy production measures, EPA should defer to state resource planning regulation and existing wholesale energy market operations.

Commenters added that the EPA based the emission guidelines on a state

- by

- state analysis of generating fleets using 2012 historical data and including new NGCC units would be a departure from that methodology and would incorporate additional uncertainty since these u nits may or may not materialize in the future. Commenters described a practical concern that natural gas conversion and co

- firing are not feasible for most coal units, primarily due to the unavailability260 of an adequate natural gas supply delivery infrastru cture nearby and/or costly efficiency and capacity penalties.

Commenters noted that the proposed section section 111(b) limit significantly exceeds Nevada's current state goals, such that Nevada could not comply with the state goal if those emissions are counted in the compliance equation, or Nevada would have to build renewable energy generation far in excess of its RPS.

Commenters described recent projects to retire coal plants and replace them with NGCC facilities at the same site in Minnesota, Wiscons in, North Carolina and Tennessee. Commenters said that the retirement/replacement projects would count toward compliance if they had occurred after 2012 and, despite the fact that they occurred prior to the EPA's baseline year, they should be exempt from B B2. Commenters stated this exemption would provide value for those companies and states that took proactive steps to shift to a lower carbon resource prior to the proposal's baseline year

. Commenters said that while some of these projects also increased th e overall capacity of the fleet, only the amount of NGCC capacity that replaced previously operating coal plants should be exempt from the 2012 NGCC capacity assumed able to redispatch in BB2. Commenters concluded that providing this exemption only to on

- s ite, coal

- to

NGCC replacements and to the capacity of coal retired (not necessarily the full capacity of NGCC installed) will provide appropriate credit to the handful of states and companies who conducted these projects, without significantly changing the overall reductions achieved nationally under BB2.

Commenters said that expanding the portion of BSER based on Building Block 2 to include re

dispatch to new NGCC and/or co

- firing natural gas increases the stringency of emission reduction targets overall and reduces the flexibility states have to achieve their emission goals.

Commenters said the way to address the inadequacies associated with the application of BSER on a state by state basis is to allow greater flexibility in compliance, not to make the B SER formula more complex. Commenters concluded that these options are valid tools states could use in the compliance plan to achieve emissions reductions required by application of BSER to their respective generating fleets.

Commenters stated it would not be reasonable for the EPA to attempt to include new NGCC capacity as a component of BSER and include it in state goals because of the tremendous uncertainty regarding new NGCC development. Commenters stated it is simply not possible to accurately determine what new NGCC capacity would be built in each state: (1) relying on announcements of new capacity builds would be inaccurate because not everything that is announced actually gets built; (2) the use of modeling also would not be an appropriate tool since modeling results are not only influenced by numerous uncertain and highly variable input assumptions but the use of modeling would be inconsistent with the EPA's decision to use a historic baseline for calculating state goals; (3) it is unclear how far int o the future the EPA would propose to estimate the amount of new NGCC to include (that year could be 2020, 2030, or any single other year, as the cutoff year selected would ultimately be arbitrary); and (4) it is preposterous to include some highly uncerta in and arbitrary amount of future NGCC capacity as a component of BSER for setting emission limits for existing coal

- fired EGUs.261 Commenters said that it is essential that separate regulatory structures apply to CO 2 emissions from existing units, new units, and reconstructed units that are reconfigured into a NGCC configuration. First, commenters said, population growth is inevitable in Colorado based on projections that indicate that the population within the northern Front Range area served by Platte River will continue to grow. Even with new energy efficiency, renewable resources and increased levels of distributed generation, commenters said that new NGCC units will be necessary to meet load growth and integrate variable renewable generation. Commenters s aid that they operate five peaker units and reconstructing one or more into a NGCC configuration should remain an available option, but this peaker reconstruction option would not be viable if regulated as an existing unit. Second, commenters added, if the emissions of new units were counted within the limits proposed by the CPP, the need for existing EGU retirements would increase significantly.

Commenters noted that EGU retirements will be required by the CPP, but section 111(d) recognizes that the "rema ining useful life" of EGUs must be considered. Commenters said that state plans should have the latitude to carefully examine and prioritize a retirement schedule in order to meet this statutory requirement, but including new and modified unit CO 2 emission s within the CPP limits is unacceptable and would likely require the retirement of all coal units by 2030 irrespective of any consideration of the remaining useful life. While commenters stated they understood that including emissions from new NGCCs in the 111(d) plan would theoretically submit them to its reduction requirements, they said the 111(d) rule does not require NGCCs to make any heat rate improvements, and the EPA already assumes that emissions from new NGCCs would not be affected by Blocks 3 and 4 because those emission reductions would be used to reduce emissions from existing plants only. Commenters did not see any benefits of this proposal and added that the much more effective and legally required alternative is to require the maximum technol ogically available degree of efficiency from all categories and sizes of new and old NGCC.

Comment 10: Commenters addressed costs related to new NGCC units as components of BSER.

Response 10: For the EPA's response to this comment see section V.A of the final rule preamble of the CPP

. The following are summaries of the specific public comments under this comment:

Commenters stated that building new NGCCs and co

- firing at existing EGUs is too expensive to be considered BSER. Commenters stated the EPA estim ates that reducing emissions through co

firing would cost as much as $150 per metric ton of CO2, while reducing emissions through re

dispatch to new NGCC units would cost as much as $81 per metric ton. Commenters stated these costs far exceed the costs of the other building blocks as well as most of the federal government's estimates for the social cost of carbon (SCC). Commenters stated these costly alternatives cannot be considered the "best system[s] of emission reduction (considering the cost of such re duction) that [have] been adequately demonstrated for designated facilities ...."262 Commenters stated that new natural gas

- fired units and co

- firing of natural gas in an existing coal

- fired unit should not be part of BSER, and added that EPA has not evaluate d the economics of these units for each specific state. Commenters noted that owners of coal

- fired units in North Dakota have invested millions of dollars to comply with the regional haze program, and that the stranded assets from shutting down these units would make new natural gas combined cycle (NGCC) economically infeasible and would raise electricity prices substantially

. Commenters stated that EPA should allow state flexibility for any new natural gas

- fired CAA s ection 111 (b) unit to be used in demonstrating compliance under CAA Section 111 (d) whether it displaces higher emitting sources or not, and that by allowing new gas

- fired units to count towards CAA

s ection 111 (d) compliance, earlier retirement of coal

- f ired units will be encouraged. Commenters added that if this option is allowed both the emissions and net generation should be included in the CAA s ection 111 (d) compliance calculation

. Commenters said that the EPA does not address how NGCC generation an d co

- firing could have been too uneconomic to justify as a part of a BSER for purposes of the proposal but can now be transformed into economic resources that can be a part of a BSER. As proposed, commenters noted, building block two assumed re

- dispatch of only existing and under

- construction NGCC facilities because the EPA assumed (wrongly) that these facilities could easily ramp up generation without the need for new infrastructure development. Commenters stated the EPA did not include new and refired NGC C facilities because the cost and time involved in building these new facilities and the associated pipeline and transmission capacity would be uneconomic. Because the NODA lacks any technical analysis that would demonstrate that new NGCC and refired gener ation qualify as a component of BSER, commenters said that the EPA cannot now declare that new NGCC and refired generation can be included in building block two. Commenters added that this approach is not formally proposed in the NODA, and the EPA cannot f inalize this approach. Commenters agreed that a BSER determination has not been made and that significant technical and environmental constraints would prevent wholesale adoption of

co

- firing across the country.

Commenters said that the EPA has not adequat ely demonstrated or accounted for the cost and reliability impacts of re

- dispatch, as required by section 111(a) because the EPA's analysis contains several flaws. Commenters concluded that if promulgated as proposed, approximately 121.5 GW, or nearly 40% of the nation's existing coal

- fired capacity, would be lost, while only 21 GW of new NGCC resources would be added.

Commenters agreed with EPA's assessment regarding the exclusion of new NGCC units within the proposed rule, noting that (1) the required add itional usage of natural gas would lead to increased commodity costs; (2) new NGCC capacity would require increased capital investment costs as compared to greater utilization of current NGCC capacity; and (3) the costs of pipeline infrastructure expansion would be significant and hard to distribute evenly among states. Commenters said that because of disparities between state pipeline infrastructure and the development costs entailed, it would be too difficult for EPA to define appropriate state

- level goal s based on an equitable and complete consideration of new NGCC capacity.

Comment 11: Commenters supported the need for new NGCC capacity to meet state goals.263 Response 11: The final rule preamble provides more clarity on the treatment of new NGCC units. N ew NGCC units are not included in the BSER and are not used for goal

- setting. See preamble section V.A.

New NGCC units are not allowed to be used to adjust CO2 emission rates at affected EGUs in state plans under a rate

- based emission standard approach. Pe rmitting new NGCC generation to qualify for ERCs would provide an incentive to shift generation from affected to non

- affected sources (i.e., leakage). Section VII.D and VIII.K.

In mass

- based states, there is a requirement for state plans to demonstrate how the state is going to address concerns regarding potential increased emissions from new NGCC units as a result of shifting generation from affected to non

- affected sources (i.e., Leakage). The EPA is giving

mass

- based states several pathways to address ne w sources and potential leakage

. Section VII.D and VIII.J.

In reference to IGCC units, a technology that is not part of the BSER and goal

- setting computation is not necessarily excluded from helping towards compliance. Many non

- BSER measures may be used fo r state plan compliance. See preamble sections VIII.I, VIII.J and VIII.K.

The following are summaries of the specific public comments under this comment:

Commenters said that construction of and re

- dispatch to new NGCC is a viable emission reduction strate gy for every state, regardless of the capacity factor of existing NGCC capacity.

Commenters said that allowing new NGCCs is important for enabling states to meet their emission rate goals without compelling the retirement of significant coal and oil/gas st eam generation. Commenters said that the CPP must recognize the critical role of new natural gas

fired generation in providing long

- term support to the transition to clean energy and maintaining reliability. Because state plans could reduce utilization of and emissions from, affected existing electric generating units through the construction of new natural gas

- fired combined cycle (NGCC) units, commenters said that states should have the discretion to include new NGCC units in compliance plans. Commenters added that the EPA should specifically confirm that new NGCCs added after the baseline date may be included in the state compliance plans.

Commenters supported accounting for emissions from new NGCC in calculation of BSER and emissions reduction targets. Commenters stated that it is unrealistic to assume that increased use of currently under

- utilized existing NGCC capacity can fully replace n on

- NGCC fossil generation displaced as a result of CPP, and that existing NGCC resources are primarily used during times of high system demand, and cannot continue in this function in addition to replacing baseload generation. Commenters stated that new NG CC resources are thus likely to be constructed to ensure sufficient capacity and energy resources are available to meet system demand, and that EPA should account for the role new NGCC will play in displacing non

- NGCC fossil generation.

Commenters said th at NGCC resources are carbon emitting resources and that EPA should account for increased emissions from existing and new NGCC resources used to replace energy and capacity contributions from displaced fossil generation. Commenters added that a failure to account for gas emissions would treat new gas generation as a non

- emitting source for purposes264 of 111(d) compliance while new gas generation would continue emitting, undermining 111(d)'s goal of reducing electric sector greenhouse gas emissions

.
Commenter s said that the EPA should provide more clarity in the rule as to how emissions from new NGCC facilities should be accounted for in 111(d) compliance demonstrations and what issues may arise in interaction with section 111(b) requirements. Also seeking cla rity, commenters said that the EPA should articulate when, if ever, NGCC units built after the effective date of the 111(d) rule may be subject to that rule rather than section 111(b)

. Commenters added that the final rule should also clarify how the three separate Section 111 rules for new sources, existing sources, and modified and reconstructed sources will interact with one another to allow the states to develop sustainable s ection 111(d) compliance plans.

Commenters said that if a state chooses to count new NGCC units under its mass cap, the state should be able to include both the generation and the emissions from these units in the goal, in parallel to how these units would be treated under a rate

- based goal. In order to accomplish this, commenters sai d that the state must be able to recalculate its mass cap to account for the additional generation from the new NGCC units, and the emissions would also count towards the limit. Commenters added that the EPA should not automatically transition "new" facili ties constructed under the proposed section 111(b) regulation into the currently proposed 111(d) regulation in the situation where the section 111(b) rule is replaced or updated.

Commenters specifically addressed the EPA's request for comment on whether in cremental emission reductions from new NGCC units that outperform the performance standards for such units under CAA section section 111(b) based on the use of CCS should be allowed as a compliance option to help meet the emission performance level require d under a CAA section 111(d) state plan. Commenters noted that the current existing fleet in Kentucky cannot meet the state's goal as proposed by the EPA, 1,763 lbs CO 2 /MWh, unless new NGCCs can be used as a compliance option. Commenters urged the EPA to promulgate specific regulatory language to ensure that the use of new NGCC, with or without CCS, be allowed by a state to achieve its goal.

Commenters said that the EPA should clarify that states may average emissions from generating units that are not sub ject to regulation under section 111(d) with emissions from affected EGUs for the purposes of calculating compliance

. Commenters stated this would allow new NGCCs to be included in the state's compliance calculations under section 111(d) as a flexible comp liance measure in state plans, while separately remaining subject to section section 111(b) emissions standards. Commenters added that the decision of whether to include new NGCCs should be left to the affected utility, based on a case

- specific assessment of whether it would be advantageous to include as part of its 111(d) compliance determination.

Commenters added that the EPA must allow states to use new NGCC capacity constructed after January 8, 2014, as a compliance mechanism to meet the state goal. Com menters stated that it is unreasonable to only allow the use of incremental new NGCC emission reductions that are below the Section section 111(b) standard, as this will provide no meaningful fleet

- wide rate improvement from the existing source pool. Also, commenters said, this ignores the fact that dispatch of new baseload NGCC may replace existing coal

- fired generation.265 Commenters agreed that new construction is needed in Arizona to meet summer peaking demand requirements in Arizona and adjacent states an d to replace the early retirement of Arizona's existing coal

- fired resources by 2020. Commenters said that the cost of new NGCC capacity is likely to be in the range of $1,000/kW, noting that installed costs will vary depending on the size of the project, technology selected, interconnection retirements, etc. Commenters added that significant associated transmission investment could also be required depending on the location of the new capacity versus the load centers in the state. In Appendix A, commenters summarized capital costs estimates for new natural gas generation to meet CPP compliance, net of the expected required investment to meet load growth through 2030, to be $1.9 billion. Commenters stated this represents an approximately 31% increase in cost s on average from 2020 to 2030 between the EPA Building Block scenario and Arizona Glide Path scenario, that would otherwise be borne by ratepayers under the Arizona Glide Path scenario gradual emission reduction plan.

Commenters believed that scaling up EE and RE is the best and least

- cost compliance pathway and urged states to focus their compliance plans on clean energy. Commenters urged EPA to set targets that reflect the opportunities presented by all three coal to natural gas options, already being d eployed across the U.S. without any carbon pollution standards in place

- and clearly adequately demonstrated, and reasonable in cost. Commenters stated all three pathways secure significant reductions in combustion carbon emissions, as well as significant reductions in harmful co

- pollutants like mercury, NOx, SOx, and particulates at the power plant stack.

Commenters supported the increased utilization of NGCC's, but added that IGCC's will be net losers in this proposal because they cannot improve their he at rate efficiency due to the nature of the process. Commenters noted that IGCC's are accounted for in the state goals, although EPA's "Goal Computation Technical Support Document" states that IGCC's are affected units but are "excluded from the generating technologies that are considered eligible for blocks one and two". Commenters stated that if a state environmental agency tried to meet the goals based on its authority alone, IGCC's would apparently not be able to help the state meet its goals as each un it stands today or even with the commercially available technologies installed on each unit.

Commenters said that the fact that the EPA cannot regulate new power plant emissions under part (d) of section 111 should not prevent the EPA from dealing with new gas in ways that point the power sector towards success in reducing GHG emissions to sustainable levels by 2030 and 2050. Commenters said that the following features are needed in the final rule:

• States should be able to take credit for avoided emissions from new natural gas, which will give them an incentive to support policies and practices that deploy gas for the purpose of providing reliability while renewable resources and clean baseload plants primarily provide the energy needed by the economy.

• Sta tes should be authorized to project lifetime carbon emissions from new combined

- cycle plants based on reasonable assumptions regarding the percentage of total energy production that would be met by new combined

- cycle gas plants between the issuance of the final rule and 2030.266 Commenters said that the CPP is inconsistent in the way that additional natural gas generation is treated compared to renewable and nuclear generation because it uses increased NGCC generation to displace generation from coal and then oil and gas boilers in calculating target emission rates but it does not do the same for efficiency and renewables.

Comment 12: Support for inclusion of new NGCC in compliance calculations, opposition to inclusion in targets.

Response 12: The final rule preamble provides more clarity on the treatment of new NGCC units. New NGCC units are not included in the BSER and are not used for goal

- setting. See preamble section V.A.

New NGCC units are not allowed to be used to adjust CO2 emission rates at affected E GUs in state plans under a rate

- based emission standard approach. Permitting new NGCC generation to qualify for ERCs would provide an incentive to shift generation from affected to non

- affected sources (i.e., leakage). Section VII.D and VIII.K.

In mass

- bas ed states, there is a requirement for state plans to demonstrate how the state is going to address concerns regarding potential increased emissions from new NGCC units as a result of shifting generation from affected to non

- affected sources (i.e., Leakage) . The EPA is giving

mass

- based states several pathways to address new sources and potential leakage

. Section VII.D and VIII.J.

The following are summaries of the specific public comments under this comment:

Commenters stated that the EPA should allow state s to include new NGCC in compliance calculations. Commenters added that the EPA should clarify that states should have the flexibility to include the emissions and generation where it is advantageous but not be forced to include a new NGCC where it would make compliance more burdensome (i.e., where the state goal is below the emission rate of an NGCC). Commenters said that the states should have discretion to determine which plants would decrease generation as NGCC generation is increased. Commenters suppo rted overall flexibility for a state to develop its own standard of performance for individual EGUs based on state specific information, cost and technical feasibility. Commenters added that EPA should avoid creating policies that incentivize new gas
power plants at the expense of existing gas power plants. Commenters stated that allowing new NGCC units to be counted for compliance incentivizes early action, and states should be allowed to count the resulting reductions in emissions and the carbon intensity of the states' generation in reaching the state's goal, as long as the new NGCC unit is added during any year after the baseline. Commenters, energy providers, said that they should be permitted to count existing and new combustion turbines as part of por tfolio compliance plans, since they have no existing NGCC capacity to re

- dispatch to, and the rule as proposed does not allow re

- dispatch or substitution of new NGCC in the compliance equation. Commenters added that Building Block 2 forces reliance on the market to address gaps in generation even though NERC has determined the CPP will cause a generation shortage. Commenters requested clarity on how the Clean Power Plan addresses a transition in situations where coal plants are retired and transition into n ew gas.267 Commenters proposed that EPA should allow any EGU (including new NGCC) whose CO2 emission rate is lower than a state's goal be factored in to the state's rate calculation for compliance purposes, noting that decreased coal

- fired generation and incr eased (intermittent) renewable electric generation sources make it important that fossil fuel generation is available for dispatch to provide critical reliability of electric service. Commenters also noted that emission rates for natural gas

- fired reciproc ating internal combustion engine (RICE) EGUs, while not as low as those typically given for NGCCs, are still significantly lower than some state goals

. Commenters recommended that states should therefore be allowed to opt natural gas

- fired RICE into their state 111 (d) plans, with the exception that CO2 emissions from these units should be exempted from CEM requirements, and instead be based on an approved mass balance basis

. Commenters described likelihood of new NGCCs being built, including because NGCC units will be needed to help integrate increasing amounts of variable renewable generation into the grid. Commenters explained that, as more renewables are brought onto the system, NGCC units will ramp up and down more frequently, or, will run at lower cap acity factors generally, which will degrade heat rates and increase emission rates.

Commenters noted that because of differences in the states, the EPA's final section 111(d) guidelines should recognize the different role that new NGCCs will play in diffe rent states if they elect this option in compliance plans. However, commenters stressed that the final guidelines should not limit states' abilities to build important base load resources when and where they are needed. Commenters described the flexibility states have to include new NGCC in their compliance plans because they are not limited to measures that the EPA has defined as BSER. Commenters added the EPA allows the states the discretion whether to include new NGCCs as enforceable measures in state pl ans depending on the approach a state takes to compliance. Commenters stated under some approaches, new NGCCs would not have to be included in state plans, but would have the effect of reducing utilization of affected EGUs. (See 79 FR at 34924

- 25) Commente rs noted that other EPA regulatory programs (e.g., MATS and regional haze) allow states to build new NGCC units as a reliable and cost

- effective way to comply with CAA standards and air quality goals, and regulations under section 111(d) should be no diffe rent. Commenters said that it is important that the EPA's final guidelines clearly state that inclusion in a state compliance plan does not mean that any new NGCC unit becomes subject to regulation under section 111(d).

Commenters stated that, consistent with the legal structure of section 111, new NGCC units appropriately are subject to the emission rate standards EPA proposed under section section 111(b) in January 2014. (See 79 FR at 1433) Using new NGCC units as compliance tools should not change their regulatory status, commenters said, and the EPA has not articulated any policy or legal rationale for regulating these units under both of these subsections of CAA section 111 simultaneously.

Commenters also agreed with the proposed compliance measure of using new NGCC to comply with existing sources.

Commenters said that it also is important that the EPA's final guidelines clearly state that units built after the CO 2 emission standards for new units were proposed (January 8, 2014) and which268 are in compli ance with those standards will not "become" 111(d) units at some point in the future. Commenters noted that states will submit compliance plans in 2016 that are designed to achieve the 2030 goal relative to the 2012 emission rate that the EPA calculated fo r each state. Commenters said that it would be inconsistent with the CAA and unfair to states if the EPA changed the goals (or determined that states were no longer making progress toward the goal emission rates) after compliance plans are approved to addr ess new NGCC units that were built after January 8, 2014. Doing so, commenters concluded would undermine state flexibility to use these units for compliance purposes, and it would undermine the certainty states and utilities need with respect to the final goals so that they confidently can invest resources to achieve them.

Commenters described the positive role that additional NGCC capacity would play in reducing Utah's compliance gap. Commenters added that the EPA should consider the possibility that low

carbon states like Washington may wish to consider building new natural gas plants, thus increasing their emissions rate, to meet new load growth demands. Commenters said that this option shouldn't be precluded for a low

- carbon state by virtue of a corresp ondingly stringent carbon reduction target.

Commenters agreed with the EPA decision to rule out CCS from the determination of BSER for existing sources and stated that this applies to new NGCC too. Commenters said that a new NGCC unit should be eligible as an affected entity at an affected source's discretion for compliance demonstration. Commenters added that NGCC that are under construction should also be considered for use as a compliance option.

Commenters agreed that EPA's finding that using expanded amounts of new NGCC capacity to provide repl acement generation should not be considered part of BSER. Commenters raised concerns regarding the EPA's predictions that pipeline capacity, natural gas supply, the transmission system, etc. are all either sufficient, or can be in the time provided, to mee t the proposal requirements in a cost

- effective manner. Commenters also disagreed that the EPA has provided any specific analysis to indicate all states can achieve this rapid increase in natural gas generation. Commenters asked how the EPA can consider ne w NGCC as a component of BSER when new NGCC would be regulated under the Section section 111(b) proposal for new sources. Commenters added that the EPA has no authority to regulate new NGCC under the existing section 111(d) regulations just as the EPA has no authority to require existing sources continue to be subject to this proposal after a modification or reconstruction.

Commenters said that the EPA should further promote new NGCC technology by providing clear procedures for its inclusion in state plan compliance demonstrations for existing sources under both rate

- based and mass

- based programs. Commenters added that the use of new NGCC to offset the use of higher emitting affected sources would result in reduction of mass emissions of CO 2

. Commenters con cluded the effect on mass emissions could easily be directly measured and reported in accordance with existing CEMS procedures.

Because new NGCC units could potentially lock in new emissions in the 2050 timeframe, commenters questioned whether new NGCC uni ts should be considered part of BSER and used to strengthen state emission rate goals. Commenters stated that better interim strategies to lower emissions through use of natural gas include shifting generation among existing generating units (already a key component of the proposed best system of emission reduction) and co

- firing with269 different fuels at existing generation units. However, commenters added, states should be permitted to use new NGCC units as part of a flexible compliance strategy.

Comment 13: Commenters expressed concerns about use of new NGCC in meeting state goals, and discussed emissions calculations.

Response 13: The final rule preamble provides more clarity on the treatment of new NGCC units. New NGCC units are not included in the BSE R and are not used for goal

- setting. See preamble section V.A.

New NGCC units are not allowed to be used to adjust CO2 emission rates at affected EGUs in state plans under a rate

- based emission standard approach. Permitting new NGCC generation to qualify f or ERCs would provide an incentive to shift generation from affected to non

- affected sources (i.e., leakage). Section VII.D and VIII.K.

In mass

- based states, there is a requirement for state plans to demonstrate how the state is going to address concerns r egarding potential increased emissions from new NGCC units as a result of shifting generation from affected to non

- affected sources (i.e., Leakage). The EPA is giving

mass

- based states several pathways to address new sources and potential leakage

. Section VII.D and VIII.J.

The following are summaries of the specific public comments under this comment:

Commenters stated that the EPA should provide additional guidance on how the generation and emissions from new NGCC facilities will be treated for the purpose s of rate

- based emission calculations and how the emissions from those facilities will be calculated under mass

- based calculations. Commenters noted that including the generation and emissions from these facilities in a rate

- based calculation in West Virgi nia would reduce the state's emission rate significantly more than only crediting the generation and emission reductions that would occur from the displacement of affected coal

- fired EGUs, but in other states these alternatives may have opposite affects. C ommenters asserted that the EPA should select a uniform method and apply it to all states.

Commenters requested clarity from EPA regarding how, or even whether, new natural gas generation can be factored into a state's plan to implement the Clean Power Pl an, considering that new power plants would be subject to the New Source Performance Standard for New Electricity Generating Units through Section section 111(b)

. Commenters stated that it is clear that new plants can be voluntarily excluded from the state 's plan, but it is unclear whether a state would be allowed to include new natural gas plants into its plan if it wishes to. Commenters referred to statements from EPA officials that states would be able to include new plants when calculating their emissio n rates, and noted that the release of the Rate to Mass Conversion TSD shows further commitment to this approach, but also noted that page 3

- 35 of the Regulatory Impact Analysis says: “ While this new NGCC capacity cannot be directly counted towards the

ave rage emissions rate used for compliance, it can displace some generation from covered sources and thus indirectly lower the average emissions rate from covered sources. ”270 Commenters supported the EPA's proposal that new sources may be included in a state's compliance plan if the state so chooses, but how these sources are treated is extremely important in states like California, whose interim and final emission rate goals are below that of a new NGCC. As such, commenters were concerned that, absent a multi

- s tate plan or regional agreement, different treatment of new sources by states in the same power market could result in negative market impacts, such as inefficient dispatch, economic distortions, and suboptimal siting of new NGCC facilities. Commenters sup ported further investigation into the impact of the treatment of new NGCC under different goal structures and compliance scenarios.

Commenters addressed the issue of how to account for emissions resulting from substitution of generation by new natural gas generation for generation by affected EGUs and whether the emissions should be calculated toward a required emission performance level for affected EGUs. Commenters stated they would require that all emissions from new generation to be addressed in the pe rformance level.

Commenters were concerned that incorrectly treating new gas generators as if they have zero carbon emissions would result in less overall carbon emission reductions, as the actual emissions associated with operating the new gas generators would not be bound by the cap created by 111(d) and would skew investment and dispatch decisions away from true zero

- emission resources as well as create a strong distortionary incentive to substitute new gas generation for existing combined cycle generat ion in investment and dispatch decisions. Commenters added that natural gas is not the solution to GHG reduction, because, among other problems, it would encourage even more fracking. Commenters said that according to the "GHG Regulation Impact Analysis

- Initial Study Results" prepared by MISO, failure to account for new NGCC capacity could result in lower utilization of existing NGCC units and lower deployment of renewable energy and energy efficiency than what is forecasted through the application of the building blocks. Commenters noted that shifting emissions from 111(d) affected units outside the framework of 111(d) to new fossil capacity when existing NGCC is available and appropriately situated to serve the load in question would likely be wasteful. Commenters concluded that this exclusion may create an unintended incentive of favoring new

- build NGCC over similar, existing NGCC resources and urged the EPA to avoid any such incentive in the Final Rule.

Commenters added that the EPA should also periodi cally reevaluate, such as during the 8

- year review process, to provide a mechanism for updating the fleet of facilities subject to the regulation in order to ensure that the 111(d) regulations continue to achieve significant emission reductions from fossil

- fuel power plants, consistent with the no backsliding policy. Commenters said that if a state adopts a program that establishes a "mass

- based" program, the EPA should require the state to account for the emissions of new NGCCs that displace existing EGUs in demonstrating compliance with emissions targets. Otherwise, commenters said, such a state might argue that it can demonstrate compliance with its mass target simply by replacing its existing EGUs with new NGCCs, without actually meaningfully reducing ca rbon emissions.

Commenters said that periodic review is important so that states and utility planners will consider the possibility that emission rate goals will continue to decline when deciding on new electric generating capacity. Commenters explained t hat the way states treat new NGCC can also affect future emissions because new NGCC is already covered under section section 111(b) of the CAA, so it isn't clear whether the EPA can require states to also include it under 111(d).271 Currently the EPA's propos al suggests that states can choose whether to include new NGCC, commenters said that if emissions from new NGCC units reside outside the 111(d) compliance program, there is the potential for emissions for the sector to increase in the 2040 timeframe even

w hile affected units are in compliance. Commenters said that the effects of including NGCC units or not will depend on the choice of program design (mass

- or rate

- based) and the choices of neighboring state program designs. For example, commenters said, inc luding new NGCC in a

mass

- based program would make the cap more stringent unless the cap is adjusted to accommodate new growth. Under a rate

- based program, commenters said, including new NGCC units could help states with higher emission rate goals meet com pliance, but could make compliance harder for states with lower emission rate goals. For states with rate

- based programs, commenters added, not including new NGCC units in the state plan could result in displacement of affected coal

- fired power generation without having to average in emissions from an NGCC plant, leading to a greater overall improvement in the emission rate for affected units.

Finally, commenters said, state(s) opting not to include their new NGCC units in the program would be more likely to build new NGCC capacity, helping meet the generation needs of their own states and also supplying power to other states within the region, particularly those that choose to include new NGCC units in their mass

- based state plans

. Commenters concluded tha t such emissions leakage would be reduced if all states incorporate NGCC units in their plans.

Commenters said that the EPA should design the standards to avoid stranding existing combined cycle natural gas assets in favor of new natural gas generation. C ommenters said that the EPA should clarify how new NGCC is to be treated should a state which to rely on natural gas to help achieve its goals. Specifically, commenters said, the accounting method should depend on the type of rate plan such that:

- In a ma ss

- based approach would count the natural gas plants' emissions when determining whether the state meets its required emissions budget amount; and

- In a rate

- based approach would count the emissions and generation of a new natural gas plant toward complia nce with a rate

- based goal.

Commenters said that because new NGCC units are built to last 40 years and will in all likelihood be part of the energy mix in 2050 when the U.S. is striving to meet a goal of 80 percent below 2005 levels, the EPA should requir e such units to be included in state plans. Commenters foresaw a compromise where such units are considered to be "new" and excluded from state plans for a few years, but then must be integrated into the 111(d) compliance goals. Commenters encouraged the E PA to specify approaches to integrate new NGCC plants for both
rate

- and mass

- based standards. Commenters stated the approach used for mass

- based standards could encourage use of a set

- aside to facilitate integration of new NGCC units. Commenters said that an increase in the state emission limit would not be needed so long as regional growth in generation was already built into the emission rate limit. Commenters added that a state that adopts a "rate

- based" program should be permitted to take new NGCCs int o account for purposes of demonstrating compliance only to the extent that the new NGCCs are proven to displace higher

- emitting existing EGUs.

Commenters said that this approach is consistent with the EPA's description of how new NGCCs would be treated in the Goal

- Setting NODA. Otherwise, commenters said, a state whose emissions rate exceeds that of a new NGCC could attempt to comply simply by introducing new NGCCs to its generation portfolio, without otherwise reducing carbon pollution from existing272 EGUs. Commenters added that the new NGCCs would bring down the state's calculated emissions rate, even while actually increasing total emissions. Commenters said that the EPA should make it clear in the final rule the Agency's authority to reject state plans tha t may meet an emissions rate goal while actually increasing overall emissions. Commenters added that the final rule should clarify that the state must account for the additional emissions resulting from the new NGCCs by adjusting its mass

- based target down ward by the amount of those new NGCC emissions, or by requiring that new NGCC plants and their emissions be covered by a single

mass

- based limit.

Commenters supported providing states with broad flexibility to incorporate new NGCC into their calculation o f compliance in meeting state emission reduction goals. Commenters suggested that this would mean that for states that choose rate

- based targets, new NGCC units that displace retiring high emitting fossil fueled units should be allowed to include the mega watts generated from new units in the denominator of the state's compliance formula. Commenters added that this approach would be similar to how renewable energy and new nuclear units are treated under the EPA's Proposed Guidelines under section 111(d).

O n the other hand, commenters said, for states that convert the rate

- based target to a mass

- based target, emissions from new units should not be counted towards compliance and should be outside the existing source program. Commenters said that the final rul e should clearly specify that a state has the option to either 1) fully utilize the new NGCC resource in its rate calculation by including the new NGCC's emissions and generation in the numerator and denominator of the rate calculation; or 2) utilize the n ew NGCC resource only to the extent that it offsets the coal emissions and coal generation that are included in the rate calculation.

Commenters said that the EPA should allow states to include in their state compliance plans the addition of new NGCC to r eplace capacity of existing affected EGUs and/or to add capacity to the state that effectively decreases the proportion of generation from higher

- emitting existing affected EGUs. Commenters noted that state rate

- based goals would still be based upon emissi on rates of the existing affected EGUs during the baseline period, but the calculation and verification of state performance towards achieving those goals would incorporate the emission rates of all new NGCC. Commenters said that this is consistent with th e existing requirement under the proposed rule that states "identify any other affected entities . . . with responsibilities for implementation and enforceable obligations under the plan." Commenters concluded that states would only receive credit for any new capacity from new NGCC.

Commenters also provided more detailed comments on the need to clarify in the final rule that
rate

- based states may take new NGCCs into account in demonstrating compliance with emissions performance levels only to the extent th at they can establish that the new NGCCs have actually displaced generation by higher

- emitting affected EGUs, and they must also account for the actual emissions from those new units when measuring compliance. Commenters said that an option is to use the s tate's change in net electricity exports as a measure of how much of its new generation merely supplements old generation, rather than displacing it or serving increased in

state load. Commenters said that a state whose new natural gas generation simply di splaces old generation or serves increased load will have no change in net exports, but a state that adds new natural gas generation without a corresponding reduction in output from existing plants or increase in load served will produce more electricity a nd thus increase its net exports (or,273 equivalently, decrease its net imports). Commenters provided an example of how this compliance calculation would work. Commenters stated the statute plainly authorizes the EPA to adopt a mechanism like accounting for a change in net electricity exports to ensure that BSER is implemented. Commenters added that, as the EPA's Legal Memorandum explains, even if the phrase "standards of performance for any existing source" is interpreted to mean that the standards of perform ance must apply directly to, and only to, the affected sources, that application of the standards of performance does not limit the scope of the type of "system of emission reduction" that may serve as the basis for the standards for emissions. To the exte nt that a state's proposed "system of emission reduction" is to displace existing EGUs with new NGCCs, commenters said, the state should be required to demonstrate that that system (which includes the new NGCCs and their resulting emissions) satisfies the standards of performance established by the BSER. Commenters added that the EPA has proposed regulations that formulate emissions standards applicable to "affected entit[ies]," and has proposed to define an "affected entity" to include "[a]n affected EGU o r another entity with obligations under this subpart for the purpose of meeting the emissions performance goal requirements in these emission guidelines."

Commenters would limit this accounting on new NGCC emissions to states with emission rate goals that are greater than the permitted rate of new NGCC units. Commenters added that recognizing that new NGCCs are not zero

- emitting resources would not hamper these states' ability to demonstrate compliance and would avoid unintended outcomes. For example,

comm enters said, if the emissions of new NGCCs are not considered, a zero

- emitting resource in a state with a goal rate greater than emission rate permitted new NGCC units could be closed and replaced with new units without affecting the state's ability to dem onstrate compliance with the emission rate goal, despite the fact that mass emissions would increase. Commenters said that to avoid this outcome, states or the EPA administratively could adjust compliance demonstrations to reflect the emissions from new NG CCs that were included in compliance plans. To incentivize the building of the newest and most efficient NGCC technologies, commenters stated that any compliance adjustments should reflect the actual emission rate achieved by the new unit, which may be low er than the 1,000

- lb CO2/MWh standard applicable to all new NGCC units (with some accommodation for the fact that the initial efficiency and emission rate of the new unit will degrade over time). Commenters stated that states with goals less than 1,000 lb/ MWh should be allowed to build new NGCCs to support integration of variable renewable resources, or to serve load.

Commenters noted that new NGCC units may not be a useful compliance option because in 25 of the 48 states that are required to submit compli ance plans, the proposed emission rate goals are more stringent than the 1,000 lb CO2/MWh standard of performance that the EPA has proposed under CAA section 111(b) . In these states, commenters said, accounting for the emission rates of any new NGCC units would be detrimental to their ability to demonstrate compliance. Commenters stated the structure of the CAA requires that existing unit standards be less stringent than new unit standards, in recognition of the fact that control technologies and improved
p rocesses can be incorporated more easily into the design of a new unit than that of an existing unit. Commenters were concerned that if these states had to adjust emission rate compliance demonstrations to account for new NGCC units, they would be function ally limited to building only zero

- emitting generation going forward. Because not all power system needs can be met using only new renewable generation and increased end

- use efficiency and the cost and long lead times involved in new nuclear generation ren der it an unlikely choice for many states,274 commenters said that new NGCC units may be needed for a variety of reasons, including: cost

effective integration of variable renewable resources, provision of other grid reliability services, and satisfying incre ases in demand. In these situations, commenters said, a state should be allowed to build new NGCC units, consistent with the proposed section section 111(b) standards, and the emissions from these units should not be included when determining compliance wi th the state emission rate goal.

Commenters said that new NGCC MWh of generation must be credited by the EPA as a zero

emission generation source because the EPA has failed to reconcile its flawed approach in requiring some states to meet more stringent e mission limits for existing sources under section 111(d) than EPA is proposing for new sources under Section section 111(b) . Commenters maintained that in a rate

- based plan, the compliance calculation must consider only the emissions reductions at the affe cted EGUs that would be replaced or reduced by the operation of a new NGCC unit. Commenters stated new NGCC units are regulated under section section 111(b) NSPS and are not subject to section 111(d), a program for existing sources. If EPA were to include emissions from a new facility not regulated under Section 111(d) in a rate

- based compliance goal, commenters said that it would undermine and invalidate the goal structure of the rule proposal. Commenters added that the inclusion of emissions from new NGCC units in compliance calculations would not only be in conflict with Section 111(d), but would place an unreasonable burden on states using a rate

- based approach, and also on states like New Jersey that already have a cleaner "affected EGU" sector than the proposed NSPS standards for new NGCC (i.e., 1,000 lb/MWh for larger units and 1,100 lb/MWh for smaller units). Therefore, commenters concluded that new NGCC MWh generation must be fully credited and CO2 emissions should not be factored.

Commenters said t hat including new NGCC NSPS emissions in 111(d) plans in states where the statewide goal is less than the NGCC NSPS is counterintuitive under a state emissions rate compliance alternative. However, commenters added, in states experiencing high electricity growth rates thereby negating a tonnage cap and forcing an emission rate compliance alternative, including new NGCC emissions may be the only method to meet the state goal where the goal is greater that the NGCC NSPS. Commenters concluded that individual S tates should be given the discretion to decide new NGCC emission inclusion into 111(d) plans.

Commenters recognized that the construction of new gas

- fired power plants are contemplated as a means of achieving compliance and intrinsically incentivized because success is measured only by reduced emissions of CO2, but noted that there are fundamental problems with the rule as presently structured

. Commenters said the most comprehensive approach to regulating GHG emissions would involve setting targets tha t account for not only carbon dioxide, but the full

cycle of total greenhouse gas emissions, including the CO2 equivalent of methane lost to the atmosphere prior to and during combustion. Commenters added that, in the absence of this, criteria should be es tablished to ensure that the rule does not favor one fossil fuel over the other, for example by applying a factor to emission estimates from gas

- fired facilities to account for methane losses or by setting separate, but equally challenging, pollution contr ol or efficiency improvement requirements for coal and gas facilities.

Commenters called attention to the NGCC penalty with high renewable energy integration and said that in the final policy the EPA should make the following changes:275 • Adjust the capacity factor for NGCC that support RE and recalculate the proposed goals with the adjusted capacity factor.

• Estimate the NGCC megawatts displaced by wind in 2012, add the displaced megawatts to actual NGCC megawatts in the baseline and recalculate the capacity factor.

Commenters provided a line chart showing "NGCC Operation with High Renewable Energy Integration" for two summer days that showed the load as well as the power contribution by wind and NGCC.

Commenters stated that new generation can have a significant impact on the environmental performance of both the state in which it is built and on any states with which it engages in electricity trade. For this reason, commenters said it is crucial that EP A require states to both account for new fossil generation in a consistent manner and account for incremental imports or exports in their demonstrations of performance. Commenters asserted that if mass standards are set under the assumption that the existi ng fleet generates a forecast number of mW

- hrs, but many of these mW

- hrs are generated instead by new NGCC sources without any adjustment to maintain the stringency of the original mass standard, overall emissions could increase significantly, again compro mising the environmental performance of state plans and of the rule as a whole. Commenters stated a similar outcome may occur if states can elect whether or not to consider the generation and/or associated emissions from new fossil generation when establis hing a standard of performance or demonstrating compliance with that standard.

Comment 14: Commenters addressed issues associated with demonstrating compliance using new NGCC capacity, particularly the different incentives in rate

- based vs. mass

- based ra te plans.

Response 14: The final rule preamble provides more clarity on the treatment of new NGCC units. New NGCC units are not included in the BSER and are not used for goal

- setting. See preamble section V.A.

New NGCC units are not allowed to be used to a djust CO2 emission rates at affected EGUs in state plans under a rate

- based emission standard approach. Permitting new NGCC generation to qualify for ERCs would provide an incentive to shift generation from affected to non

- affected sources (i.e., leakage). Section VII.D and VIII.K.

In mass

- based states, there is a requirement for state plans to demonstrate how the state is going to address concerns regarding potential increased emissions from new NGCC units as a result of shifting generation from affected t o non

- affected sources (i.e., Leakage). The EPA is giving

mass

- based states several pathways to address new sources and potential leakage

. Section VII.D and VIII.J.

The following are summaries of the specific public comments under this comment:

Commenters noted differing incentives under rate

- based vs. mass

- based rate plans, and stated that under a mass

- based approach, the incentives with respect to investment in new natural gas276 generation work in the opposite direction from that for a rate

- based standard. Commenters added that if states are adopting a mass

- based approach and thereby capping their emissions, excluding new natural gas generation would create a strong bias toward premature closure of existing capped facilities and their replacement by new, unc apped power plants, while under a rate

- based compliance approach, excluding new natural gas generation decreases the incentive for new investment. Commenters concluded that if new natural gas generation is not regulated under the Plan, investment incentive s are distorted one way or another under both the mass

- based and rate

based emissions standards. Commenters urged EPA to encourage states to integrate existing and new sources of generation in their implementation plans, and stated that including new and

e xisting sources under the same mass

- based standard would eliminate the incentive to over

invest in new generation.

Commenters noted the EPA's requests for comment on how emissions changes under a rate

based plan resulting from substitution of generation b y new NGCC for generation by affected EGUs should be calculated toward a required emission performance level for affected EGUs. Commenters agreed that under a mass

- based plan where an emission limit on affected EGUs would assure achievement of the required level of emission performance in the state plan, any emission reductions at affected EGUs resulting from substitution of new NGCC generation for higher

- emitting generation by existing affected EGUs would automatically be reflected in mass emission reduct ions from affected EGUs, and a state would not need to include enforceable provisions for new NGCC in its plan. Under a mass

- based approach, commenters said that emissions from new NGCC would not and should not be accounted for when demonstrating complianc e, which is appropriate because new NGCC units would not be affected units under section 111(d). For states that use the mass

- based approach under section 111(d), commenters agreed that the emissions from newly constructed units should not be included in t he program at all.

Commenters said that under a rate

- based plan where an emission rate limit on affected EGUs would assure achievement of the required level of emission rate performance in the state plan, any emission rate reductions at affected EGUs resul ting from substitution of new NGCC generation for higher

- emitting generation by existing affected EGUs would also automatically be reflected in any emission rate changes from affected EGUs, and a state would therefore not need to include enforceable provis ions for new NGCC in its plan. Commenters said that as with the

mass

- based approach, emissions and generation from new NGCC capacity would not need to be accounted for when demonstrating compliance. However, commenters added, while new NGCC units are outsi de of the section 111(d) program, to the extent these newly constructed NGCC units displace higher

- emitting generation units, states should be given wide latitude to decide how to address new NGCC for purposes of calculating compliance. Commenters said tha t it would be permissible for a state that employs the rate

- based approach under section 111(d) to allow the megawatt hours generated by newly constructed NGCC units to be included in the denominator for a state's rate calculation. Commenters said that thi s approach would be similar to how renewable energy and new nuclear units are treated under the Proposed Guidelines.

Commenters said that the effect of the proposed Plan on incentives to build new gas generation depends significantly on a state's choice be tween a mass

- based versus a rate

- based standard and that these considerations become more complex when states with different regulatory approaches share a common power market. Commenters gave an example where state A adopts a mass

-277 based approach and state B adopts a rate

- based one. Commenters added that we should assume that both states have emissions rate targets above that of an efficient new combined cycle gas turbine (CCGT). Commenters said that state A, the capped state, will want to reduce its utiliza tion (and emissions) from its existing sources. If new sources are also covered, commenters said that state A could increase its imported power from state B, while state B builds new CCGT capacity and lowers its average emissions rate in the process. Becau se the implied production cost for "cleaner" generation is lower in the rate

- based states, commenters said that it will be more attractive for all parties involved to allow the new investment in the rate

- based state, B, and transfer the power to the capped state A.

Commenters added that if new plants are excluded from the regulation, this bias toward investment in rate

- based states is diluted. Commenters said that state A, the capped state, still has an incentive to shift production from existing sources, b ut is largely indifferent as to where those new sources are located because it could be just as economic to build new capacity within state A as outside it. Similarly, commenters added, state B's incentive to create more low carbon generation is largely mu ted by the fact that this extra production would not aid its progress toward lowering the average emissions rate from existing sources. Commenters concluded that, just as a mix of mass and rate

- based regulations would increase inefficiencies in the short r un operations of regional power markets, a hybrid

- approach to compliance would also distort investment decisions, likely in favor of building new plants in rate

- based states instead of mass

based ones.

Commenters said that excluding the emissions and elect ricity generation at new sources from the calculation of a state's emissions rate for compliance purposes will distort investment decisions and undermine progress toward cost

- effectiveness goals. Commenters stated one of the desired benefits of building (o r repowering) efficient gas generation is to lower the average emissions rate under a rate

- based standard, particularly in states with little or no current excess gas generation capacity. Commenters said that excluding new generation from this calculation would therefore reduce the incentive for new investment, as it would provide at best indirect progress toward compliance.

Commenters raised concerns about the scenario where existing source standards for many states (e.g., VA, NC, SC, AZ) are more stringen t than the standards for proposed new sources and said that these states are disadvantaged relative to states with targets higher than the level of the new source standard that can use new NCGCC generation as a means to comply with their targets. Commenter s said that, to the extent new NGCCs can help offset requirements under section 111(d) plans, states should be given wide latitude to decide how to address new NGCC for purposes of calculating compliance. Commenters stated that the emission rate analysis E PA conducted under its section 111(b) proposal should hold true under the current 111(d) proposal since EPA evaluated all existing NGCC generation before setting the emissions rate limit for new units.

Commenters added that the EPA requested comment on all owing incremental emission reductions beyond what is required of new units under section section 111(b) to count toward compliance with section 111(d). Commenters supported this concept, and requested that the EPA make clear that states are free to find ot her, similar incremental emission reductions that could also be applied toward compliance with the section 111(d) program.278 Commenters said that their ability to comply with the CPP is dependent on compliance via rate

based goals, and that they must be perm itted to substitute new NGCC units in place of retired coal units and to include existing peaking gas units in emission rate compliance calculations. Commenters added that such flexibility is essential if the CPP is to be achievable and if natural gas is g oing to be the primary fuel for electricity generation.

Commenters stated that the EPA should affirmatively avoid broadly giving all states even more incentives to further deploy new gas plants

- and especially of new combined

- cycle plants operating at hig h capacity factors

- for the purpose of supplanting the production of existing power plants.

Commenters answered EPA's request for comment on how to address emissions new NGCC units and suggested considerations for states who are demonstrating compliance with emission performance goals for affected units of different sizes. Commenters noted EPA's assertion that accounting for emissions from new NGCC units when making compliance demonstrations is only an issue if states choose a rate

- based approach to compl iance, and states that the relevant consideration is not whether a state chooses a rate

- or a mass

- based approach, but whether compliance is assured via emission limits on affected units. Commenters added that because compliance is measured at the stack of affected units, accounting for new NGCCs could be an issue for both rate

- and mass

- based compliance plans.

Commenters said that it is appropriate for states with emission rate goals greater than 1,000 lb CO2/MWh to include emission rates of new NGCCs when making a compliance demonstration because it would not harm these states' ability to demonstrate compliance and would avoid unintended, but perverse, environmental outcomes. Commenters offered an example that if emissions of new NGCCs are not considered, a zero

- emitting resource in a state with a goal rate greater than 1,000 lb CO2/MWh could be closed and replaced with new NGCC units without affecting the state's ability to demonstrate compliance with the emission rate goal, despite the fact that mass emis sions would increase. Commenters suggested that states or EPA administratively could avoid this outcome by adjusting compliance demonstrations to reflect emissions from new NGCCs built to help decrease the emission rate of the in

- state fleet of affected un its. Commenters added that to incentivize the building of new and efficient NGCCs, compliance adjustments should reflect the actual emission rate achieved by the new unit, which may be lower than the 1,000

- lb CO2/MWh standard applicable to all new NGCC uni ts.
Commenters said that new NGCC units may not be a useful compliance option for States with Goals Less than 1,000 lb CO2/MWh. Commenters stated that in 25 of the 48 states required to submit compliance plans, the proposed emission rate goals are more str ingent than the 1,000

- lb CO2/MWh standard of performance that EPA has proposed under CAA section 111(b) , and that in these states, accounting for the emission rates of any new NGCC units would be detrimental to their ability to demonstrate compliance becau se EPA has proposed state goals for existing units that are more stringent than the proposed standards for new units. Commenters noted that if these states had to adjust emission rate compliance demonstrations to account for new NGCC units, they would be f unctionally limited to building only zero

- emitting generation. Commenters observed that current power system needs cannot be met using only new renewable generation and increased end

- use efficiency, that new nuclear generation is unlikely for many states b ecause of cost and long lead times, and that as a result new NGCC units may be needed. Commenters279 suggested that in these situations a state should be allowed to build new NGCC units, consistent with the proposed section section 111(b) standards, and the e missions from these units should not be included when determining compliance with the state emission rate goal.

Commenters stated the EPA should consider carefully whether incentives should be given for construction of new facilities by including them in the calculation of the demonstrated emissions
rates.

Commenters stated that exclusion of new NGCC facilities from the universe of affected EGUs can create electricity market distortions and put existing efficient NGCC facilities at a disadvantage. Commente rs said that in electricity systems with least cost economic dispatch, the
cap

- and

- trade allowance price of $10/ton will be embedded into the bids for affected EGUs and, thereby, their electricity will be more expensive, while new NGCC units (if they are n ot included within the state program) could sell power into the same markets more cheaply. Commenters added that this would create economic distortions

- a "new plant effect" which would cause new sources to move to a relatively higher position and existin g NGCC units to a relatively lower position in the dispatch queue, resulting in lower dispatch rates for existing NGCCs than would otherwise occur (including highly efficient existing NGCC units that, solely due to the fact that they were constructed prior to January 8, 2014, would be considered affected EGUs under the Clean Power Plan.) Commenters noted that if new sources are exempt from emission control program compliance costs, those costs, borne by existing sources, would effectively become subsidies for developers to build new sources which could, in turn, incent the construction of more new capacity than is really necessary to meet the emission reduction requirements of the Clean Power Plan. Commenters said that this additional new capacity would pus h existing capacity lower into the dispatch order and possibly out of business altogether

. Commenters added that even though new sources might see lower apparent compliance costs, the total compliance cost to the generating sector and ultimately to ratepa yers could be increased overall relative to the most economically efficient solution. Commenters noted that an even more undesirable outcome could arise if a new coal plant with carbon capture and storage (CCS) that meets NSPS limitations were also exempt from complying with the Clean Power Plan: potentially a coal

- producing state could provide incentives that would make construction of a coal plant with CCS economically attractive, particularly if that plant bore no emission obligation related to its remai ning CO2 emissions. Commenters stated that this could potentially have the impact of increasing emissions as a result of exclusion of a source.

Commenters stated that EPA should encourage states to include equivalent requirements for existing and new NGCC units in their state plans, and supported EPA's inclusion of presumptively approvable mass

- based goals for both affected EGUs and new sources in the Mass Conversion TSD. Commenters added that this would increase the likelihood that states follow the most e conomically rational system for regulation by providing incentives to use mass

- based programs in their submittals, adding that such incentives could include streamlined program approvals if state submittals meet certain criteria set up by EPA.

Commenters stated that EPA must take action to avoid these market distortions, and that nothing in the structure of Section 111 suggests that Congress intended for new plants to forever be grandfathered from coverage under state 111(d) plans

. Commenters stated that E PA can, within the structure of Section 111, periodically broaden the scope of affected EGUs by revising the280 GHG NSPS for stationary turbines at least every two years, so that, upon revision, stationary combustion turbines that were constructed after Janua ry 8, 2014, but prior to the proposed revision of the NSPS, would become affected EGUs. Commenters suggested that EPA should implement a streamlined process for revising the GHG NSPS for stationary combustion turbines by standardizing data sources and sett ing expectations for continual CO2 emission rate improvement

. Commenters added that this can be accomplished by identifying, through rulemaking, the exact data sources from which data will be drawn to support revision of the NSPS and the schedule for revie w of such data to determine the appropriate revision to the NSPS

. Commenters stated that EPA should also clarify in the final rule that, once a new NSPS is proposed, NGCC units that commenced construction pursuant to the pre

- existing NSPS would become affe cted EGUs under the Clean Power Plan.

Commenters said that EPA should require that each state plan describe either how the plan is designed to accommodate the addition of new affected EGUs or the process that the state will undertake to revise the emissio n standards for each affected entity, if necessary, in the event that the state experiences the addition of an affected EGU, and that EPA should clarify the availability of the revision process for inclusion of such newly affected EGUs when it finalizes th e Proposed Rule. Commenters added that states could avoid the potential market distortions that would arise during the period prior to EPA's proposed revision of the GHG NSPS by simply including equivalent requirements for both new and existing NGCC facili ties in their respective plans at the outset.

Comment 15: Commenters said that the CPP does not provide sufficient time for compliance with BB2 through addition of new NGCC capacity.

Response 15: Building block 2 of the BSER does not include adding new N GCC capacity, only shifting generation to existing natural gas generating capacity. New NGCC units are covered under the CAA section section 111(b) rule for new sources. For the EPA's response to this comment see section V.A, of the final rule preamble of the CPP

. The following are summaries of the specific public comments under this comment:

Commenters said that the EPA must provide adequate time for the siting, planning, design, permitting, and construction of new generation resources and supporting infra structure (e.g., new electricity transmission and gas pipeline). Commenters noted that siting and permitting transmission or pipeline on federal land can take 10 years or more and nonattainment constraints (requirements for emissions offsets) close to load pockets can further limit NGCC facility siting. Commenters assessed company

- specific options for the Apache Station under the CCP and said that, even assuming that siting and transmission issues could be overcome in time, the cost of building a new NGCC u nit that will comply with the proposed EGU NSPS is likely in the range of $1100 to $1400 per kilowatt and it is unlikely that a new resource could be brought online prior to 2020.

Commenters said that the EPA has not provided states with sufficient time to comply with BB2 through new generation because, based on the timeline the EPA proposed, many states will have,281 at best, 2 years to implement their compliance plans (assuming state plan submission in June 2016 and EPA approval 1 year later)

. Commenters added that many states could have as little as 6 months (assuming multi

- state plan submission in June 2018 and EPA approval 1 year later) to shift massive amounts of coal and oil/gas steam generation to NGCC generation in order to satisfy the Pr oposed Rule's Building Block 2

- imposed interim goals.

Commenters provided an example: the EPA also encourages more use of gas resources, even though a broad range of restrictions pose barriers to this increased use: since NGCC facilities may not exist in each state, NGCC facilities must be sited, permitted, and procured (even though the resource may be duplicative of existing non

- gas resources); existing CAA permits may have operational limits that will be violated; existing contracts for the purchase of e nergy from those resources may be repudiated; pipeline supplies may not exist; or even firm gas contracts at expensive rates are unavailable. Commenters provided an example: gas distribution companies typically have firm pipeline capacity rights and can di splace supplies to NGCC in the event of heavy usage during the home heating season. Commenters stated electric transmission capacity may be insufficient to accomplish the proposed dispatch. Commenters said communities may be resistant to new facilities and new pipelines, increasing cost and time to achieve the result. Commenters stated the Agency does not address these issues.

Comment 16: Commenters described potential inequities between the states under a system allowing new NGCCs under goal setting and/o r compliance demonstrations.

Response 16: The final rule preamble provides more clarity on the treatment of new NGCC units. New NGCC units are not included in the BSER and are not used for goal

- setting. See preamble section V.A.

New NGCC units are not allo wed to be used to adjust CO2 emission rates at affected EGUs in state plans under a rate

- based emission standard approach. Permitting new NGCC generation to qualify for ERCs would provide an incentive to shift generation from affected to non

- affected

sourc es (i.e., leakage). Section VII.D and VIII.K.

In mass

- based states, there is a requirement for state plans to demonstrate how the state is going to address concerns regarding potential increased emissions from new NGCC units as a result of shifting generat ion from affected to non

- affected sources (i.e., Leakage). The EPA is giving

mass

- based states several pathways to address new sources and potential leakage

. Section VII.D and VIII.J.

The following are summaries of the specific public comments under this c omment:

At a public hearing, commenters requested clarification on whether states can use the new natural gas plants to comply with emission targets, since EPA has not factored these plans into the establishment of new targets. Commenters stated that there must be symmetry between the resources considered in setting the target or the standard and the resources allowed for compliance, or some states with modest targets will achieve their goals simply as a result of implementing their existing plans to close old coal plants and replace them with new natural gas plants.28 2 Commenters identified how the CPP's treatment of NGCCs is anomalous and may lead to interstate inequities and unintended consequences, particularly for early adopters of NGCC fleets. Commenters stated that EPA's approach to calculating the state

- specific emission rate goals disadvantages states and electric utilities that already have undertaken investments in new NGCC capacity to reduce emissions from affected EGUs by assigning them more stringe nt targets.
Commenters added that differential treatment of existing (under Section 111(d)) and newly constructed NGCC units (under Section section 111(b) ) under the EPA's proposed rules places a potentially inequitable economic burden upon early acting st ates that have already begun their transition to an NGCC fleet. Commenters described how modeling and general economic and technological trends show that natural gas generation is economically competitive against coal generation across much of the USA.

Co mmenters said that states which have already built NGCC fleets in response to the low cost of natural gas in the 1990s and for environmental concerns are now faced with a more constrained treatment (and concomitant costs) of their NGCC fleets under Section 111(d) relative to those states who will now begin transitioning to natural gas for similar economic and environmental reasons, constructing an NGCC fleet relatively unconstrained in emissions under Section section 111(b)

. Commenters compared the State of Louisiana (which has a very low goal even more stringent than EPA's proposal for new sources due to its substantial gas generation fleet) to Kentucky (which has no existing gas

- fired generation and a goal with almost no requirement to displace coal genera tion) and stated that EPA's goal setting calculation unfairly penalizes Louisiana's more balanced generation mix. Commenters stated that Congress did not intend for EPA to use Section 111(d) to set state

- by

- state existing source performance standards, but instead intended to authorize the states to decide what appropriate measures to take to reduce emissions from the sources located within their borders.

Commenters added that EPA's prior Section 111(d) emission guidelines didn't create these types of issues because those prior emission guidelines only required emission reductions using techniques that could be applied to a single facility, and that decisions regarding the level of reductions for each facility were historically left to states by EPA. Commente rs added that the current proposed rule has generated new issues never before considered by stretching the scope of Section 111(d) to require emission reductions through a re

- ordering of the entire power sector, including facilities that do not emit anythi ng at all and should not be subject to the jurisdiction of the Clean Air Act. Commenters stated that EPA would largely eliminate these unfair unintended consequences by withdrawing its Proposal and replacing it with a program that fits within the legal con fines of Section 111(d) to require emission reductions at individual covered sources that would, if new, be regulated under Section section 111(b)

. Commenters noted that although the EPA does not include the potential for new NGCC plants in a state's targe t rate calculation, the proposal does allow a state the option to count new NGCC capacity towards compliance with its target, which results in an inconsistency between target

setting and compliance, as well as an effective dual penalty for states like New York in which the proposed target CO2 emission rate is already lower than that of a typical new NGCC power283 plant. In other words, commenters said, although the proposal allows new NGCC to be used for compliance purposes, this opportunity is not actually av ailable for New York and other states with relatively low CO2 emission targets.

Because substantial new natural gas capacity has been constructed in numerous states over the past several years, commenters said that the EPA should incorporate at least some potential for

re

- dispatch from existing coal or oil/gas steam units to new NGCC plants into Building Block Two. For example, commenters said, in New York 18 new NGCC units came on

- line between 2004 and 2011, increasing the State's natural gas

- fired namepl ate capacity by approximately 150% in a 7

- year period. Commenters noted that by contrast, given that the CPP's state targets are for 2030, a state has a 16

- year period to increase its NGCC capacity. Therefore, commenters said, including some potential for re

- dispatch to new NGCC capacity into Building Block Two would achieve additional emission reductions nationwide and more accurately reflect demonstrated emission reduction measures, and result in greater equity in states' targets. When incorporating the potential for new NGCC capacity into Building Block 2, commenters said that the EPA could consider technical and economic feasibility, just as it does through the alternative approach to renewable energy in Building Block 3.

Comment 17: Commenters raised general issues associated with developing new natural gas capacity.

Response 17: For the EPA's response to this comment see section V.D of the final rule preamble of the CPP and the Natural Gas Pipeline and Electricity Transmission sect ion of Chapter 3 of the GHG Mitigation Measures TSD for CPP Final Rule supporting the final CPP

. Also see Preamble Section V for discussion of the Building Blocks and Section X.A for discussion of the NSR issues referenced in the comment.

The following are summaries of the specific public comments under this comment:

Commenters stated that not all states will have adequate natural gas availability and capacity to fuel their coal

- fired EGUs and that it would be a mistake for the EPA to assume that co

- firing is universally obtainable and practical in all cases and that any corresponding co

- benefits would be available in all states. Commenters asserted that co

- firing with natural gas or full conversion to natural gas will likely constitute redefinition of a per mitted source and additional permitting requirements, including PSD/NSR review would be triggered. As an extension of Building Block 1, commenters said that the co

- benefits of natural gas co

- firing could simply be counted by tracking net electrical generat ion and CO2 emissions, and calculating a composite CO2 rate on a unit or facility level. Since these units will have implemented BSER, commenters said, their generation should be excluded from re

- dispatching under Building Block 2.

Comment 18: The EPA should give more consideration to methane emissions from new NGCC.

Response 18: For the EPA's response to this comment see sections V.A and V.D of the final rule preamble of the CPP

. Methane emissions are discussed in the RIA, Chapter 3.284 The following are summaries of the specific public comments under this comment:

At a public hearing, commenters stated EPA should be concerned about life cycle emissions from NG production and move forward with parallel measures to ensure methane pollution does not erase th e climate benefits of increased reliance on natural gas over coal.

Commenters said EPA has not made the case adding new NGCC as a component of BSER because it ignored two critical issues: (i) venting and leakage could be much higher than industry estimates and (ii) the 10 to 30 year time scale of Arctic

- related climate disruption, best represented by a 20

- year global warming potential for methane. Commenters stated that increased use of NGCC generation may not be a viable compliance mechanism given that the net CO2eq emission reductions could be a fraction of the EPA estimate or possibly close to zero, even after taking coal

- related methane venting reductions into account. Commenters said that EPA has a considerable burden of further analysis before it can a llow the increase of natural gas use in electricity generation as a compliance mechanism for greenhouse gas emission reductions from the power sector.

Commenters stated that adding new NGCC as a component of BSER may not be possible because CO2eq emissions may increase rather than decrease due to the impact of methane venting. Commenters reanalyzed EPA's Option 1 (state scenario) using other available estimates of methane emissions and provided evidence from multiple studies pointing to the conclusion that leakage and venting are higher nationally than official estimates. Commenters also noted EPA's assumption that regulatory and voluntary measures would reduce natural gas venting per unit production, and suggested that EPA should parse these elements in the rule so the role of regulations in the venting rate reduction is shown separately from the more uncertain voluntary reductions.

Commenters provided references and analyses to support their assertion that EPA should take the much higher 20

- year global warm ing potential for methane into consideration with regard to adding new NGCC as a component of BSER, including evidence that thresholds ("tipping points") are being reached that could severely disrupt climate on a time scale of a few decades even if the lon g term CO2 emission trajectory is kept to a 2 degree C average temperature rise. Commenters stated that the CPP fails to account for the evolution of the time frame of estimates of the time when the Arctic would be essentially ice

- free, and that this neces sarily means using a 20

- year (or even a 10

- year) global warming potential for methane.

Commenters also noted that in addition to reduced emission estimates, higher methane emissions also mean that remaining CO2eq emission reduction estimates would be produ ced at much higher cost than estimated in the CPP. Commenters stated that the CPP estimates the cost of using NGCC to reduce CO2 emissions by displacing coal

- fired generation as $21 per metric ton, and states that they estimate the cost to be between about $40 and $58 per metric ton using venting and leakage rates from their cited references, even reducing those rates by about a third due to assumed regulatory and voluntary measures emission reduction measures

.
Comment 19 : Commenters stated that the Proposed Rule should allow states to meet their rate

based targets by replacing older, more carbon intensive units with newer units, particularly NGCC units. Commenters continued, (verbatim) EPA appears to agree with this compl iance285 method, and says as much both in the June 18 Proposed Rule and its October 28 NODA. Commenters asserted that EPA's Proposed Rule, however, could be read to exclude Section section 111(b) sources like new NGCC from the definition of "affected entity." Commenters stated, by doing so, the Proposed Rule disincentivizes both the replacement of existing coal

- fired EGUs with new NGCC units and the addition of new NGCC units to provide substitute generation or meet future demand (hereinafter, collectively ref erred to as "New NGCC") in states that opt to utilize rate

- based targets. Commenters noted, similar to EPA's proposal to include modified or reconstructed units

- units otherwise subject to Section section 111(b) standards

- within Section 111(d) plans, EP A should allow New NGCCs subject to regulation under CAA section section 111(b) to function as compliance sources under section 111(d). To accomplish this, commenters suggested that EPA should specifically state in the Final Rule that states may include Ne w NGCCs as "affected entities," or, at a minimum, should amend the definition of "affected entities" so that it does not exclude New NGCC. Commenters said the states then would be able to use New NGCC as a compliance mechanism both for affected EGUs (by al lowing the substitution of CO2 emission rates from retired or lesser

- utilized coal

- fired EGUs with lower rates from new NGCC capacity) and to meet or maintain state emission rate targets if additional capacity is need for future demand. Commenters stated t hat EPA has the option to determine whether this would specifically impact BSER for affected EGUs and allow the flexibility to include this option in individual state programs. Commenters said, in EPA's Proposed Rule Building Block 2, increased utilization of NGCC units, EPA recognized the CO2 reduction benefits that could be realized with existing generation from the increased utilization of natural gas. Commenters said EPA has recognized that the increased utilization of NGCC units will naturally factor i nto compliance. Commenters said, however, EPA suggests in the preamble that only existing NGCC would "displace" a coal

- fired unit. Commenters stated, in reality, coal displacement will be achieved in large part by the construction and operation of new NGCC . Further, commenters said if the rules are read to exclude New NGGC capacity from state targets, this creates disincentives to adding new NGCC capacity. Commenters stated, unless all states are permitted by rule the option of accounting for New NGCCs in t heir section 111(d) state plans, the present exemption practically ensures that newly constructed NGCCs will have little to no impact on state average CO2 emission rates. And because many states will choose to adopt a
rate

- based approach and most NGCC unit s will not be constructed until after the Proposed Rule is effective, commenters stated that the majority of New NGCCs will not be a factor towards achieving compliance with the Proposed Rule. Commenters said a simple example demonstrates the challenge of incentivizing New NGCCs in states with rate

- based compliance targets. Commenters said to suppose the state contains 4 existing coal

- fired units that generate equal amounts of electricity, each with a CO2 emission rate of 2000 lbs/MWh. The average emission rate for those 4 units is 2000 lbs/MWh. One of the 4 units is then retired; however, the retired unit is replaced (or will be replaced in the near future) with a New NGCC unit. Then, due to increases in demand, an additional New NGCC unit is constructed in the state. Both New NGCC units have a lower CO2 emission rate of 1000 lbs/MWh. Commenters noted, under the rule as proposed, in a rate

- based state, the retirement of the coal

- fired unit has no effect on the average CO2 emission rate. Commenters said nor d oes the addition of New NGCCs (whether replacement, substitution or additional capacity). Commenters said the average rate remains286 2000 lbs/MWh (now averaged over 3 units). See Scenario A below. Commenters said only if the emission rate from the New NGCC u nits are accounted for would the state's average emission rate decrease to 1600 lbs/MWh ((2000 lbs/MWh *3 units + 2000 MWh) / 5 units). Commenters suggested that new NGCCs should be regarded as satisfying the definition of an affected entity if used by ret ired affected EGUs as the compliance mechanism to meet the emission performance targets of the state. Commenters noted, similarly, new NGCCs may be used to achieve the state emission rate target, accounting for a growth in future demand, which as EPA has

a cknowledged, is a practical reality that states and regulators alike must prepare for, by increasing the proportion of generation from low

- carbon EGUs. Commenters said, as illustrated above, under either scenario, the growth of New NGCCs has a positive net benefit on lowering the overall rate of carbon emissions in the state, while maintaining the reliability of the electric system. To accomplish this, commenters suggested that EPA should permit states to include in their state compliance plans the addition of New NGCCs to replace capacity of existing affected EGUs and/or to add capacity to the state that effectively decreases the proportion of generation from higher

- emitting existing affected EGUs. Commenters said state rate

- based targets would still be bas ed upon emission rates of the existing affected EGUs during the baseline period, but the calculation and verification of state performance towards achieving those targets would incorporate the emission rates of all New NGCCs. Commenters stated that this is entirely consistent with the existing requirement under the Proposed Rule that states identify any other affected entities with responsibilities for implementation and enforceable obligations under the plan. Commenters said states would only receive credi t for any new capacity from New NGCCs. Commenters asserted, importantly, designating New NGCC as an affected entity under the Proposed Rule would not conflict with the exception under section 60.5800, which applies only to affected EGUs. Commenters suggest ed, under the Proposed Rule, state plans must establish "standards of performance" for its affected EGUs. Commenters noted that the use of New NGCC as a means for a state to achieve its performance standards at its affected EGUs is consistent with this req uirement. Commenters did not propose that EPA designate a New NGCC as an affected EGU. Commenters stated, by limiting the applicability of New NGCCs to affected entities, the new units act merely as a compliance mechanism for the state to achieve its rate

- based target for purposes of CAA Section 111(d). Commenters noted that the New NGCCs would still need to meet all applicable requirements under CAA Section section 111(b) . Commenters said subjecting New EGUs to the requirements of both CAA Sections section 111(b) and 111(d) is entirely consistent with EPA's proposed handling of modified or reconstructed sources under the Proposed Rule. Commenters said, generally, existing units that are modified or reconstructed constitute "new units" under CAA Section 111( a) and are subject to the regulatory requirements under CAA Section section 111(b) , much like a newly constructed unit. However, commenters said modified or reconstructed existing sources would remain subject to the state's CAA Section 111(d) plan. Comment ers noted that the same logic should apply to any new NGCC units constructed to replace existing coal

- fired units subject to a state's 111(d) plan or to add capacity and lessen the overall proportion of state generation from higher

- emitting coal

- fired unit s. Commenters stated, to hold "new" units, modified or reconstructed, to burn natural gas as eligible compliance mechanisms for a section 111(d) plan but not more efficient New NGCC is to find a distinction without a practical difference. Commenters said, as noted above, in states287 with rate

- based targets, the addition of New NGCC units is a reasonable and effective compliance mechanism to reduce CO2 emission rates while ensuring that those states have sufficient capacity to meet expected increases in demand . Without the ability under a state's 111(d) plan to account for emission rate reductions from New NGCC units, commenters asserted that the rule as proposed jeopardizes the integrity of any existing rate

- based plan by ignoring the benefit of increasing the proportion of generation from low

- emitting NGCC units. Commenters suggested that EPA should incentivize the construction of New NGCC units by including New NGCC in the rule as affected entities to allow for such units' use as a specific compliance option

. Response 19 : EPA disagrees

. EPA has determined that new NGCC is not BSER, and New NGCC units are not included in the goal computation nor compliance demonstration (for states with a rate

- based emission performance standard). For the EPA's response to thi s comment see sections V.A, and VII.D of the final rule preamble of the CPP.
New NGCC units are not allowed to be used to adjust CO2 emission rates at affected EGUs in state plans under a rate

- based emission standard approach. Permitting new NGCC generatio n to qualify for ERCs would provide an incentive to shift generation from affected to non

- affected sources (i.e., leakage). Section VII.D and VIII.K.

In mass

- based states, there is a requirement for state plans to demonstrate how the state is going to addr ess concerns regarding potential increased emissions from new NGCC units as a result of shifting generation from affected to non

- affected sources (i.e., Leakage). The EPA is giving

mass

- based states several pathways to address new sources and potential lea kage

. Section VII.D and VIII.J.

3.10 HEAT RATE REDUC TION OPPORTUNITIES F OR NON

- COAL FOSSIL FUEL

FIRED EGUS

This subsection primarily addresses public comments which questioned whether the EPA properly estimated and included in its quantification of buildi ng block 1 the heat rate improvement and CO2 reduction potentials of gas and oil

- fired EGUs. It also addresses certain comments regarding the fact that simple cycle combustion turbines are exempt from this CPP final rule. We have responded to many of these comments in the preamble to this CPP final rule and, where appropriate, this section makes reference to the relevant preamble section for such
responses.
Commenters have raised a number of issues related to the subsection which are organized by topics (c omments) below. Responses are also provided for these topics. Additionally, comment summaries are noted below the responses.

Comment 1: A few commenters asserted that building block 1 was arbitrary and capricious in focusing on coal

- fired EGUs alone.288 So me commenters assert that the EPA’s proposed national average heat rate improvement goal, derived from an analysis of only coal

- fired EGUs for building block 1, is unfair for states that have primarily gas

- fired EGUs and therefore already have a significan tly lower CO2 emission rate than states with primarily coal

- fired EGUs.

Commenters have also stated that the EPA has significantly underestimated the amount of CO2 emissions from natural gas

- fired EGUs on a lifecycle basis (considering methane leakage, etc .), and therefore also underestimated the amount of emission reductions that building block 1 could accomplish.

Response 1: The EPA disagrees with the commenters’ assertion that building block 1 was arbitrary and capriciou s in focusing on coal

- fired EGUs alone.

A few commenters incorrectly interpreted the EPA’s method of quantifying the potential for CO2 reductions under building block 1 as limiting the applicability of the CPP rule to only existing coal

- fired EGUs

– as though all other existing fossil fu el

- fired EGUs were exempt from the rule. We reemphasize that with certain limited exemptions this final CPP rule applies to existing coal, natural gas, and oil

- fired EGUs. The agency’s rationale for applicability of this final rule is presented in preamble section IV.D.

Some commenters stated that heat rate improvement via equipment upgrades for oil and gas

steam EGUs and for NGCC units are available, are not prohibitively expensive, and that the EPA should have estimated and included in building block 1 an amount of CO2 reduction achievable by application of upgrades to such EGUs. The EPA considered this possibility in the Technical Memorandum, Consideration of Heat Rate Improvement (HRI) Potential at Existing Oil/Gas

fired Steam, Natural Gas Combined Cycle , and Combustion Turbine EGUs for Inclusion in Building Block 1 , which is an appendix to the GHG Abatement TSD in the proposal docket. For the reasons stated in that Technical Memorandum, the potential for CO2 reduction achievable via upgrades at oil and g as steam EGUs is relatively small compared to that from the existing fleet of coal

- fired EGUs. While some of these commenters provided estimates to illustrate the significance of potential CO2 reductions from gas and oil

- fired EGUs, none of the estimates

c ontradict the EPA position that such reductions are small relative to the reductions that can be obtained from coal

- fired EGUs. The EPA does not suggest that relatively small CO2 reductions from fossil

- fired sources other than coal

- steam EGUs are not impor tant. Potential reductions via equipment upgrades might be significant in some oil and gas

- fired EGU situations at this time, and may become more significant in the future with increasing utilization of gas

- fired EGUs. States are of course free to consider the availability of such reductions in developing state plans. However, because of the relatively smaller reductions available from upgrades at these EGUs, and in light of the substantial resources required to separately assess available heat rate improve ments at oil and gas

- fired EGUs, the Agency is not at this time developing such an assessment. Rather, the Agency has decided to focus its resources at this time on the larger CO 2 reduction potential of affected coal

- fired EGUs.

Some commenters stated tha t the EPA should have performed a “variability analysis” for NGCC units, similar to that performed for coal

- fired steam EGUs in the proposal, and that the EPA should have used that analysis to estimate and include in building block 1 an amount of CO2 reduc tion achievable by application of best practices to NGCCs. We considered performing this289 analysis for the proposal, and decided against it for several reasons. Foremost are the facts that many NGCC owners do not report hourly generation data for the steam turbine generator portion of the EGU, and that many owners do not indicate whether or not they are reporting total generation. 2 The derived hourly heat rates for an indeterminate number of such units would thus be grossly inaccurate. While it may have been possible to develop a smaller subset of NGCC units for variability analysis

- units which have heat rates in a range suggesting that total generation data were likely reported

- we decided not to attempt this in part because we were aware of several addit ional factors that would have caused any NGCC analysis to have a much greater degree of uncertainty than our analysis of coal

- fired units. First, there is a greater historical extent of cycling (both part load and on

- off duty) for many NGCC units, as refle cted in the historically lower fleet wide annual capacity factors for NGCC units. Second, the heat rate of NGCC units are more sensitive to variations in both ambient air temperature and percent load, which would have required the use of smaller capacity

- f actor temperature bins. This would have reduced the amount of data in each bin, and therefore reduced our confidence in the overall analysis. Finally, the various physical configurations of a NGCC unit, often including multiple combustion turbines that can be operated independently at widely varying loads and heat rates, makes a variability assessment even more complex. The EPA was properly concerned that the inherently greater uncertainty associated with a NGCC heat rate variability analysis would offset
t he reasonable level of confidence that we would normally to attach to our estimates.

The EPA disagrees with commenters’ assertion that the EPA’s proposed national average heat rate improvement goal, derived from an analysis of only coal

- fired EGUs for buil ding block 1, is unfair for states that have primarily gas

- fired EGUs and therefore already have a significantly lower CO2 emission rate than states with primarily coal

- fired EGUs. At proposal, the heat rate improvement was assumed to be uniform across all states. That did not unfairly penalize states with a large gas generation portfolio because the state goal was a product of expected coal generation and heat rate improvement at those coal

- fired facilities, so the less that coal generation factored into a state's generation mix (i.e., gas

- intensive states), the smaller the impact that heat rate improvement had on that state’s goal. In this final rule, the EPA takes a regionalized approach in defining heat rate improvement expectations, and establishes unif orm CO 2 emission performance rates reflecting the overall BSER for two source categories of fossil fuel

- fired EGUs

. Both of these changes also work to obviate the commenter s ' concern.

The EPA disagrees with commenters’ assertion that the EPA has significantly underestimated the amount of CO2 emissions from natural gas

- fired EGUs on a lifecycle basis (considering methane leakage, etc.), and therefore also underestimated the amount of emi ssion reductions that building block 1 could accomplish. We have considered methane leakage to the atmosphere from coal and gas production/transport. The technical details supporting our analysis can be found in the

2 See “Part 75 Emissions Monitoring Policy Manual,” 2013, Section 17.2, Load and Heat Rate Determination for Combustion Turbines and Cogenerators, available at http://www.epa.gov/airmarkets/documents/monitoring/Final

- Part75

- Policy

- Manual

- 2013

- revised

- 08

- 27

- 13.pdf290 Appendix to chapter 3 of the proposal an d final RIAs. Section 8.7 in this response to comments document also includes a discussion of this matter.

The following are summaries of the specific public comments under this comment:

Commenters stated that the agency should also incorporate into the ta rget reductions from carbon capture and storage and BSER for oil and gas steam powered units.

Commenters stated that in its current proposal for Building Block 1, EPA assumes heat rate improvements will occur at coal

- fired EGUs only. Commenters stated that the agency has articulated no basis for excluding oil and gas ("O&G") steam units from Block 1's emission reductions, in spite of the fact that some of these units exhibit very high heat rates. Commenters stated that the data presented also shows that the re is a greater disparity among heat rates at gas

fired steam units than among the coal

- fired fleet. Commenters provided Figure 11 , entitled :

“ Heat Rates of Coal

- fired EGUs v. Natural Gas

- Fired Steam EGUs ” . Commenters stated that EPA has sufficient data to determine the difference between the best rolling annual average emission rate and the long

- term average at each O&G steam unit. Commenters stated that this would permit the same determination of an O&M

- based heat rate improvement for those units as they have already proposed for coal

- fired EGUs based on the 52

- Unit Study. Commenters stated that furthermore, there is no reason to believe that plant upgrades, such as turbine blade replacements, would be any less effective at EGUs based on the differences in the fuel that generated the steam. Commenters stated that accordingly, any determination of BSER for the entire fleet of regulated EGUs must cover O&G steam units under Building Block 1.

Commenters stated that under Building Block 1, EPA has estimated an average six percent improvement of the coal

- fired steam EGUs in each state. Commenters stated that EPA proposes to base this estimate on coal

- fired steam EGUs only because the potential for reductions is "significantly greater" from these EGUs. 79 Fed. Reg . at 34,859. Commenters stated that even though potential heat rate improvements in NGCCs are not as significant as in coal

- fired steam EGUs, EPA should also estimate heat rate efficiency upgrades from natural gas

- fired units, and make this type of efficie ncy upgrades available for compliance by these sources. Commenters stated that stationary combustion turbines are also a regulated source category under Section 111, and under EPA's proposal they would not be subject to emission reduction requirements in t he form of reductions in carbon intensity.

Commenters stated that EPA needs to estimate achievable heat rate improvements, not just from existing and under

- construction NGCCs currently covered under Building Block 2, but also from existing simple

- cycle com bustion turbines ("CTs"). Commenters stated that as they explained in their comments to EPA's proposed carbon pollution standards for new EGUs, new small combustion turbines would not covered under the Section section 111(b) standard if they operate at cap acity factors of less than 33 percent. Commenters urged EPA to finalize a Section section 111(b) standard that covers these new CTs, and to also cover all existing CTs under the Section 111(d) emission guideline. Commenters stated that as EPA notes, measur es to improve affected sources' heat rates are a common and well

- established practice in the industry. Commenters stated that heat rate improvements cause fuel to be used more efficiently, thus reducing the adverse impacts associated with the disposal of c oal combustion solid waste products. 79 Fed. Reg. at 34,882. Commenters stated that there is no reason why EPA should not factor the291 potential for heat rate improvements of natural gas

- fired EGUs in setting the stringency of the standard, which would resul t in greater environmental benefits than currently estimated under Building Block 1.

Commenters recommended that EPA should include heat rate improvements for oil

- and gas

fired EGUs in its determination of BSER for these units. Commenters also recommende d that the determination of BSER in the final rule should not include mandatory conversion to or co

- firing of natural gas, because it may not be technically or economically feasible for all affected EGUs. However, commenters stated emission reductions from voluntary fuel switching or co

- firing should be allowed for the compliance demonstration.

Commenters stated that EPA claims that although heat rate improvements have the potential to reduce CO2 emissions from all types of affected EGUs, the potential is significantly greater for coal

- fired steam EGUs and therefore, "EPA is conservatively proposing to base its estimate of CO2 emission reductions from heat rate improvements on coal

- fired steam EGUs only."79 Fed. Reg. at 34859. Commenters stated that EPA doe s not provide any data to support its bald assertion that the potential for heat rate improvements is significantly greater for coal

- fired steam EGUs than others and instead, provides only a cursory justification for not providing a detailed assessment of this potential, which is contained in the Appendix to the GHG Abatement Measures TSD. Commenters stated that efficiency improvements should have been considered for all carbon

- emitting EGUs

- natural gas, oil, and coal

- fired and that the singular focus on coal

fired EGUs is clearly arbitrary and capricious

. Commenters stated that EPA is arbitrarily focusing on heat rate improvements at coal

- fired power plants to the exclusion of consideration of such improvements at other carbon

- emitting generators of elec tricity.

Commenters stated that EPA proposes not to require any reduction measures for oil and gas steam powered EGUs, but admits this proposal was made without undertaking a detailed assessment of potential fleet

- wide emissions reductions for this source. Commenters stated that EPA performed just such an assessment for coal

- fired EGUs, which demonstrates that the assessment is possible. Commenters stated that such a biased approach in undertaking this rulemaking is arbitrary and capricious.

Commenters stat ed that EPA cites three reasons for forgoing further study of this pollution sector. Commenters stated that first, EPA maintains that "oil and gas contain significantly less carbon per unit of heating value than coal." Commenters stated that the relative d ifference in combustion emissions between coal and other fossil fuels is not determinative of whether those emissions can be reduced through application of BSER, especially in light of the life

- cycle emissions of methane during gas extraction, storage, tra nsport and distribution, and methane's proper GWP and leakage rate. Commenters stated that in any event, even if oil and gas steam

generated power overall creates fewer emissions than coal

- fired generation, that fact alone does not justify allowing this so urce of pollution to evade section 111(d) without independent analysis.

Commenters stated that EPA's second reason for skipping the analysis is that oil/gas steam EGUs are utilized much less frequently that coal

- fired steam EGUs. Commenters disagreed that small292 amounts of potential emission reductions are unworthy of analysis. Commenters stated that third, EPA states these units have a lesser range of opportunities for implementing heat rate improvements. Commenters stated that does not mean no such opportu nities exist, and does not establish the absence of BSER. Commenters stated that EPA cannot exempt an entire class of power plants from BSER without engaging in the necessary analysis.

Commenters stated that EPA has failed to incorporate many adequately de monstrated systems of heat rate improvement into Block 1 and EPA readily admits that "the measures in the building blocks could be implemented more stringently to achieve greater emission reductions." Commenters stated that EPA discusses and solicits comme nt on potential emission reduction methods that it excluded from BSER, including heat rate improvements at affected EGUs beyond those proposed, fuel switching from coal to gas at individual coal

- fired EGUs, carbon capture and storage, and build

- out of a ne w NGCC fleet. Commenters stated that although EPA believes these measures "merit discussion," it "does not propose to consider [these measures] part of the best system of emission reduction adequately demonstrated for existing EGUs." Commenters agreed with EPA's assessment in a few instances, but in most others believe that excluding available reduction measures from BSER is unjustifiable.

Commenters stated that EPA has solicited comments regarding its tentative conclusion that existing gas fired combined c ycle EGU's are not capable of efficiency improvements that would reduce CO2 emissions per megawatt hour of output. Commenters stated that EPA appears to have made this determination based on its belief that heat rates do not vary significantly from
one gas

- fired EGU to the next. Commenters stated that that assumption is wrong, as evidenced by the heat and emission rate data reported by the industry and made available online through the Clean Air Markets Division.

Commenters stated that they analyzed the av erage annual heat rate and emission rate (CO2 lbs/MWh) for 565 combined cycle EGU's, and 18 large simple cycle units. Commenters stated that annual heat rates for the top quintile (the best performing 20%) averaged 6.79 MMBtu per gross megawatt hour betwee n 2009 and 2013, or 19% lower than the five year average for all EGU's in the study. Commenters stated that the emission rates for best performers averaged 807 pounds of CO2 per megawatt hour on an annual basis between 2009 and 2013, or 19 % lower than com parable emission rates for all gas fired units within the study. Commenters stated that its analysis suggests that CO2 emissions could be reduced an additional 43 million tons per year, if EPA recalculated its proposed state

- wide emission rates based on an assumption that all combined cycle units in 2030 had attained average heat and emission rates comparable to those achieved by the most efficient units today.

Commenters stated that there are multiple reasons to include heat rate improvements for gas

fired EGU's when calculated statewide emission rates that must be met by 2030 and listed the following:

1. Gas

- fired EGU's already account for a greater share of electricity generation than coal in twenty

- two states, and are expected to continue to increase market share for the foreseeable future. Furthermore, EPA's proposal assumes that combined cycle units will run at 75% of capacity (much higher than current levels) before electricity from coal fired units is dispatched. While carbon dioxide emissions from gas

- f ired units are significantly293 lower than coal

- based generation, they are nevertheless substantial and there is no sound reason for not requiring such plants to maximize their efficiency to reduce such pollution.

2. EPA's assumption that there is little long

- te rm variability in heat and emission rates among combined cycle gas

- fired EGU's is simply incorrect. Heat rates averaged over five years at the most efficient gas

- fired units are 40 % lower than rates from the bottom fifth of the units in their analysis, an d 19 % lower than average five year rates for all units in the study. As with coal

- fired units, their analysis is based on heat rates and emission rates that gas

- fired EGU's have maintained over a very long period, to screen out any short term variations t hat may result from sudden changes in operation conditions or other factors.

3. Natural gas boilers typically have a shorter life cycle than coal

- fired units, making it more likely that the least efficient units will have been retired by 2030.

4. EPA clearly has the authority to set emission rates under 111(d) based on reasonable estimates of what the industry as a whole is capable of achieving over the next fifteen years. EPA is not required to show that each unit covered by a standard has already met the propos ed emission limit at some point in the past, or even that each unit as currently designed can meet the limit without any physical upgrades.

Commenters stated that EPA assumed that gas

- fired units were not capable of improving heat rates over the next fift een years. Commenters pointed to a study that evaluated an alternative based on emission rates already achieved by the best performing coal and gas fired units within the past five years. Commenters stated that approach required:

1. determining the heat rates and emission rates achieved by the best performing 20% of coal and gas fired EGU's, compare those to the rates achieve by other EGU's,

2. evaluating the emission reductions that could be obtained if coal or gas fired EGU's achieved heat rates or emission rat es comparable to those already achieved by the best performing 20% of the industry today;

3. comparing the results

- in terms of heat rate improvements and carbon reductions

- to EPA's proposal.

Commenters stated that the natural gas analysis includes 583 EGU s at 233 power plants. Commenters stated that EIP also selected these units based in part on the criteria in the Proposed Rule; each has an achievable heat rate capacity of 250 MMBtu/hour, and average annual gross generation of at least 240,000 MW

- h over t he 5

- year period from 2009 through 2013. Commenters stated that since net generation data was not available for these units, EIP chose a gross generation threshold of 240,000 MW

- h, assuming a parasitic load of 8.75%. Commenters stated that only plants with a capacity factor of 30% or higher between 2009 and 2013 were included in the analysis. Commenters stated that the capacity factor for gas

- fired units was determined by dividing annual gross generation by the theoretical maximum summer capacity of each un it. Commenters stated that gross generation data was obtained from CAMPD, while total summer capacity was obtained from EIA

- 860 Schedule 3. Commenters stated that the study is294 limited to coal and gas

- fired units for which generation, heat rate, and emissio ns data were available for each of the five years between 2009 and 2013.

Commenters stated that EIP determined annual CO2 emission rate for each calendar year between 2009 and 2013 for each of the selected units by dividing the annual CO2 emissions reporte d to CAMPD for a given year by the annual net or (for gas units) gross generation for the same year. Commenters stated that net generation data for each coal

- fired unit was obtained from the EIA

- 923 Monthly Generating Unit Net Generation Time Series File f or years 2009 through 2013, while gross generation was obtained from CAMPD. Commenters stated that EIP calculated the annual CO2 emission rates averaged over the five year period for the units in both the coal and gas analyses, ranked the units from the lo west to highest rates, and sorted the data into quintiles.

Commenters stated that CAMPD data was used to identify the annual heat input (MMBtu) data from 2009 through 2013 (inclusive) for all coal and natural gas

- fired units included in each analysis. Com menters stated that heat rates for coal

- fired units was calculated by dividing the heat input by the net generation reported in EIA

- 923 Monthly Generating Unit Net Generation Time Series File. Commenters stated that EIP determined heat rate for natural gas

- fired units by dividing the heat input by the gross generation, both of which were reported in the CAMPD.

Commenters stated that EIP calculated possible improvements in CO2 and heat rate using scenarios based the percent change formula found in EPA's GHG Abatement Measures Technical Support Documents for Carbon Pollution Guidelines for Existing Power Plants. C ommenters stated that EIP calculated percent change by subtracting a new number (X2) from an old number (X1), dividing the total by the old number and multiplying by 100 to yield the percent change between the two values:

((X1

- X2)/X1) * 100 = % Change

C ommenters stated that EIP estimated potential CO2 reductions by assuming that each unit could meet the annual average emission rates achieving by the best performing 20% within each category between 2009 and 2013.

Commenters stated that EPA notes that the re is "potential to reduce CO2 from all types of affected EGUs" but the Agency nonetheless elected to base its estimates of emission reductions on HRI achievable at coal

- fired steam EGUs only. 79 Fed. Reg. at 34,859. Commenters stated that in the Proposal, EPA solicits comments on whether the final rule should include other types of EGUs in Building Block One, as the basis for BSER. Id. Commenters stated that because both EPA's and EIP's data indicate that reductions at natural gas

- fired EGUs are achievable , and because states may rely on reductions in CO2 emissions at natural gas

- fired EGUs to achieve targeted rates, EPA should take achievable reductions into account when setting state goals that reflect BSER. Commenters stated that by excluding natural

- gas fired EGUs from Building Block One, EPA's Proposal fails to account for significant, achievable reductions in carbon emissions which should be included in the Agency's BSER determination. Commenters stated that Building Block One should therefore include emissions reductions achievable by natural gas

- fired EGUs and these reductions should be included in the calculation of state goals. Commenters stated that295 furthermore, the level of emissions reductions required for natural

- gas fired EGUs should be based o n emissions rates achievable by the most efficient units.

Commenters stated that EPA's assumption that there is little long

- term variability in heat and emission rates among combined cycle gas

- fired EGU's is simply incorrect.

Commenters stated that heat r ate and carbon emissions vary widely across natural

- gas fired EGUs that would likely come within the purview of this rule. Commenters stated that EIP evaluated the CO2 emissions and generation data at 583 natural gas

- fired EGUs and broke units into 5 group s of 116

- 117 units based on each unit's CO2 emission rate. Commenters stated that as in the analysis of coal

- fired units, Group One represents the best

- performing units (those with the lowest CO2 emissions rates), and Group Five represents the poorest

- perf orming units (those with the highest CO2 emissions rates). Commenters stated that EIP's analysis revealed that there is significant variability in the CO2 emissions rates between Group One and Group Five. Commenters provided a data table on page 17 of thei r comments showing the "# of Units", "CO2 Emission Rates (CO2/MWh) ", and the "MMBtu/MWh" for Combined Cycle and Combustion Turbines in five (5) CO2 Emission Rate Groups.

Commenters stated that this demonstrates that there is significant room for improveme nt among poorer

- performing sources, given that the best performers emit about 66% less CO2 than the worst performers. Commenters stated that this is a much more significant gap in performance across the industry than with respect to coal

- fired steam EGUs. Commenters stated that EIP therefore believes that there is substantial justification for EPA to include reductions achievable from natural

- gas fired units in Building Block One of its BSER determination.

Commenters stated that gas

- fired EGU's already acco unt for a greater share of electricity generation than coal in twenty

- two states, and are expected to continue to increase market share in the foreseeable future.

Commenters stated that in addition to variability in heat rates and GHG emissions, there is

s ignificant variability from state

- to

- state in the prominence of natural gas

- fired generation in their electric fleet. Commenters stated that due to this variability, it is important for EPA to take natural gas into account when formulating Building Block O ne. Commenters stated that EIP analysis of EIA data indicate that in 2012 there were 22 states that relied more heavily on natural gas than on coal for electricity generation. Commenters stated that this is the case for other years as well; on the aggregat e over the 2008

- 2012 period there were 19 states in which EIA attributed a larger percentage of net electricity generation to natural gas than coal. Commenters stated that EPA acknowledges this fact in the Proposal, stating that "the proportion of total ge neration provided from EGUs such as . . . gas

- fired steam EGUs varies by location . . . ." 79 Fed. Reg. at 34877. Commenters stated that however, EPA premises the second prong of its rationale for excluding natural gas

- fired steam EGUs from the basis for B uilding Block.

Commenters stated that one on the assertion that "coal

- fired steam EGUs are utilized at much higher levels compared to oil/gas steam EGUs." GHG Abatement Measures at A

- 2. Commenters stated that while EIP's analysis confirmed that coal is re sponsible for more generation in aggregate than natural gas, this is not true at the state level, the level on which EPA sets state296 goals. Commenters stated that EIP included a list of states in which natural gas fleets generate more electricity than coal

- fired EGUs.

Commenters stated that EPA should include natural gas

- fired EGUs in Building Block 1. Commenters stated that considering emissions reductions achievable by natural

- gas fired EGUs on an industry

- wide basis would result in significant GHG reducti ons beyond those proposed in the rule.

Commenters stated that when EIP examined the existing fleet of natural gas

- fired EGUs, EIP found that there are opportunities to improve heat rates and therefore reduce GHG emissions from natural gas

- fired EGUs. Comme nters stated that there is significant variability between the most and least efficient natural gas

- fired EGUs. Commenters stated that there is also significant variability at these individual units between the unit's best performing year and average perfo rmance. Commenters stated that on the whole, there was a 4.65% gap between a natural
gas

- fired EGU's typical performance and its best performing year. Commenters stated that interestingly, for the most typical EGUs, those in Groups 2, 3, and 4, combined, E IP found an even larger gap between average performance and the EGU's most efficient year. Commenters stated that for those groups, EIP found that there was a 5.62% gap in performance. Commenters stated that Group 4 had the largest performance differential between the best and average years, with a 12.23% gap. Commenters stated that this seriously undermines EPA's finding that there is little room for improvement at natural

- gas fired facilities. Commenters provided a data table on page 19 of their comments showing Rate improvements. Commenters stated that given variability in the heat rate performance and carbon emissions between individual natural gas

fired steam EGUs, EPA should calculate potential CO2 emissions rates by comparing poorer performing units w ith best performers. Commenters stated that while EIP argues that any reasonable approach that brings natural gas

- fired EGUs within the fold of Building Block 1 is an improvement over the rule as proposed, tying performance to the industry leaders is the b est approach. Commenters stated that EIP's analysis demonstrates significant variation between the best and worst performing groups of natural gas

- fired steam EGUs.

Commenters provided a data table on page 20 of their comments entitled "Natural Gas

- Fired S team EGUs CO2 Emission Rate Group, CO2 Rate and Heat Rate" showing the CO2/Gross Gen (lbs./MW

- h) & Heat Rate (MMBtu/Gross MW

- h) for five (5) CO2 Emission Rate Groups. Commenters stated that if the study population as a whole met the Group 1 CO2 emission ra te there would be an overall improvement in emission rate of 19.37% and this would reduce carbon emissions by 86.96 billion pounds per year in the facilities included in the EIP analysis. Commenters stated that in addition, it would enable EPA to set more stringent goals in states with large gas fleets currently deployed. Commenters stated that as with coal, these numbers represent reductions which the existing fleet can achieve even without any improvement at the top

- performing sources. Commenters stated t hat EIP's analysis of best performing natural gas

fired EGUs is based on annualized data, and thus, as with reductions from coal

- fired units, these numbers do not capture heat rate improvements that could be achieved at top performing sources. Commenters s tated that here too, it is reasonable to expect that additional natural gas

fired EGUs could achieve additional reductions beyond those proposed in the rule. Commenters stated that while this methodology would result in a more demanding standard than curre ntly proposed by EPA, EIP's analysis nonetheless represents a conservative estimate of possible reductions.297 Commenters stated that EIP's Findings Cast Doubt on EPA's Rationale for Excluding Natural

Gas Fired EGUs from the Purview of Building Block One.

Com menters stated that in the Proposed Rule, EPA presents three reasons for excluding natural
gas

- fired EGUs. Id. at 34,877: (1) EPA argues that because oil and gas produces less carbon per heat unit than coal, these fuels are less important contributors to a mbient GHGs, and do not warrant inclusion in the rule (GHG Abatement Measures at A

- 2), (2) at present, natural gas

- fired EGUs are utilized at much lower levels than coal

- fired EGUs, and EPA argues that as a result even a 6% HRI at natural gas

- fired units w ould not achieve the emissions reductions possible through a 1% HRI at coal

- fired steam EGUs. Id., and (3) due to less extensive equipment needs at natural gas

- fired EGUs as compared to coal, EPA believes that natural gas

- fired EGUs have fewer opportunitie s to improve heat rates through maintenance. Commenters stated that they respectfully disagree with this analysis and believe that the existing opportunities to achieve emissions reductions through HRI at natural gas

- fired EGUs are critical to achieving th e purposes of the rule.

Commenters stated that EIP's findings show that natural gas

- fired EGUs contribute significant GHG emissions. Commenters stated that EIP believes that, as a result of these findings, natural
gas

- fired EGUs warrant inclusion in the Pr oposal. Commenters stated that EPA notes in its rationale for excluding natural gas

- fired EGUs from Building Block One that because natural gas is already a superior form of generation as compared to coal, no GHG reductions at gas

- fired sources should be r equired. Commenters stated that this approach is flawed for two reasons: first, as discussed below, EIP found that there are significant opportunities to reduce carbon emissions from existing natural gas

- fired EGUs, resulting in between 26 and 87 billion f ewer pounds of carbon emissions. Commenters stated that although that savings is smaller than from HRI at coal

- fired steam EGUs, it is nonetheless significant. Commenters stated that second, EPA's argument incorrectly assumes that natural gas

- fired EGUs sh ould not be subject to Building Block One because they are already operating very efficiently. Commenters stated that EIP's data do not support this finding. Commenters stated that in fact, as discussed below, EIP found significant room for improvement at natural gas

- fired EGUs. Commenters stated that the best performers produce about 40% less CO2 than the worst performers.

Commenters stated that second, EPA argues that because, at present, coal

- fired steam EGUs comprise a significantly larger portion of el ectricity generation than natural gas

- fired EGUs, the potential emissions reductions from HRI at gas EGUs is less than at coal

- fired EGUs and therefore does not warrant inclusion in the basis for Building Block One. Commenters stated that EIP takes issue w ith this for two reasons. Commenters stated that first, CO2 savings available from HRI at natural gas

- fired EGUs are significant and should be included in EPA's BSER determination. Commenters stated that second, while on the whole coal generation is respon sible for more carbon emissions than natural gas

- fired EGUs, this is not true everywhere; in certain states natural gas is responsible for a significant portion of electricity generation, and thus, a significant portion of the state's carbon pollution. Com menters stated that in light of this, and especially because the Proposed Rule encourages the portion of electricity generation from natural gas

- fired EGUs to increase, it is important to reductions achievable by natural gas

- fired units in Building Block O ne.298 Commenters stated that according to both EIP's and EPA's analysis, the potential CO2 savings from natural gas

- fired EGUs are substantial, particularly in certain regions. Commenters stated that EIP proposes methodology for calculating the most effectiv e HRI at natural gas

- fired EGUs above. Commenters stated that this has the potential to reduce carbon emissions by between approximately 26 and 87 billion pounds per year over the implementation period. Commenters stated that based on EPA's analysis in the Regulatory Impact Analysis accompanying this Proposed Rule, the portion of natural gas

- fired EGUs is slated to increase between 4% and 9% by 2020, 11% and 16% in 2025, and between 18% and 19% by 2030. Commenters stated that EPA, Regulatory Impact Analysis at 3

- 27. Commenters stated that because natural gas

- fired generation is projected to increase over the life of the Proposal, it is critical that EPA require these facilities to operate efficiently, and limit their carbon emissions accordingly.

Commenters stated that finally, EPA must include natural gas

- fired EGUs in the basis for Building Block One even if many facilities already have incentives to operate at optimal efficiency. Commenters stated that EPA concludes that, because of the common structure of operations and maintenance contracts at NGCC facilities and financial considerations create incentives for many operators to run natural gas

- fired EGUs at or close to optimal efficiency, HRI "are likely already being applied across most of the NGCC fleet. " GHG Abatement Measures at A

- 5. Commenters stated that EIP found that there was significant variability in GHG emissions. Commenters stated that this demonstrates that existing economic incentives are insufficient to compel best performance. Commenters st ated that EPA must include natural gas

fired EGUs in the Proposed Rule's Building Block One.

Commenters stated that particularly in states in which natural gas units comprise a large portion of the existing fleet, by excluding natural gas

- fired EGUs from B uilding Block one, EPA underestimates the emissions reductions which should legally be required of existing sources. Commenters stated that given that EPA readily acknowledges that states are free to include all kinds of EGUs in their state plans, EPA's em ission guideline should account for reductions available through HRI at natural

- gas fired units.

Commenters stated that in any event, EPA's cavalier dismissal of the entire oil

- and gas

- fired power plant sector from this rulemaking based on "preliminary" conclusions and scant inquiry is arbitrary and capricious. Commenters stated that in asserting that the size of reductions available from natural gas plants was "relatively small," EPA compared them only against those available from coal plants. Commenters stated that in absolute terms, however, emissions from natural gas fired electricity generation are highly significant by themselves. Commenters stated that the Energy Information Administration's most recent reference case (AEO2014) projects natural gas power plants will emit nearly 422 million metric tons of CO2 in 2014, increasing to 478 million metric tons in 2020 and 545 million metric tons in 2030.

Commenters stated that the sheer magnitude of these emissions requires EPA to determine how they can be reduced through BSER. Commenters stated that these emissions are smaller "relative" to coal is quite irrelevant. Commenters stated that EPA has not made a determination that the cost of these measures would be excessive, nor has the agency concluded that

- or even examined whether

- such heat rate improvements are technologically infeasible. Commenters stated that without a full analysis and explanation, EPA cannot simply dismiss HRI measures for NGCCs and simple cycle combustion turbine (CT) plants from t he Proposed Rule.299 Commenters stated that EPA must establish BSER for NGCCs. Commenters stated that EPA states that because NGCC EGUs are "only" expected to provide 20% of all fossil

- fuel generated CO2 emissions in 2020, the agency "conservatively decided n ot to separately itemize and include" available heat rate improvements that its "preliminary conclusion" estimated would yield 2

- 3% of additional emission reductions in Block 1. Commenters believed that correcting for accurate methane GWPs and leakage rate , the base emissions number for 2020 will rise, and so will the percentage of emission reductions achievable. Commenters questioned why emission reductions of 2

- 3% are not worth pursuing. Commenters stated that in any event, EPA has limited its projections of natural gas

- based emissions to the period up to 2020, leaving increases through 2030 and beyond unexamined. Commenters requested that EPA perform a full analysis through 2020 and complete that analysis at least through 2050 and, preferably, through 208 0. Commenters stated that even assuming NGCCs contributed "only" 20% of the sector's pollution over the lifetime of the Proposed Rule, EPA cannot simply forgo assessment of BSER for the sources responsible for one

- fifth of the pollution EPA is charged to r educe. Commenters stated that capturing all readily available emission reductions inside the fence line of NGCCs is crucial, particularly in light of EPA's proposal to increase the NGCC utilization rate from 55% to 70% utilization. Commenters stated that w ithout a full and accurate assessment, and without the proper cost/benefit analysis, EPA's dismissal of BSER for NGCCs is unsupported and unexplained.

Commenters stated that moreover, other statements contradict EPA's preliminary conclusion that HRIs could yield no more than some 2

- 3% of emission reductions. Commenters stated that specifically, EPA states that "a very efficient NGCC can further reduce the CO2 emission rate per MWh to about 60% less [from 40% less] than that from coal

- steam EGUs." Commenters stated that although this reference likely discusses the efficiency of newly constructed NGCCs, EPA has not analyzed the extent to which existing NGCCs could adopt some of the technology that yields these efficiency improvements. Commenters stated that ev en if improvement is feasible only for specific subcategories of NGCCs, EPA must at a minimum examine what is in fact adequately demonstrated.

Commenters stated that EPA also states that it rejected BSER for NGCC units because a lack of "unit specific det ailed design information" prevented the agency from determining "best practices and upgrades for each NGCC unit." Commenters stated that EPA, however, has had many years to obtain that information and has no excuse for not informing itself and moreover, la ck of such detailed knowledge is legally irrelevant. Commenters stated that to set BSER, it is simply not necessary that "each NGCC unit" in existence can meet the resulting standard, as long as BSER has been adequately demonstrated.

Commenters stated that Section 111(d) requires EPA to set the standard to reflect the emissions limits achievable through the "best system of emission reduction taking into account the cost ... and any nonair quality health and environmental impact ... the Administrator determi nes has been adequately demonstrated." Commenters stated that while EPA did not consider the potential role of Turbine Inlet Cooling when setting the state emission targets, TIC satisfies these requirements. Commenters stated that more thoroughly in their recent analysis (Attachment), TIC (1) reduces CO2 emissions, (2) is cost effective, (3) enhances electric reliability, and (4) is adequately demonstrated. Commenters stated that EPA should highlight these benefits in the final rule and expressly state that TIC is a valuable compliance tool for affected units,300 notwithstanding its omission from the building blocks. Commenters stated that Building block two contemplates increasing the average utilization rate of NGCC units to 70 percent. Commenters stated that TIC would allow for even greater utilization of these units, thus reducing the need for states to rely as heavily on the other building blocks to achieve their targets.

Commenters stated that Turbine Inlet Cooling technology (TIC) provides a cost

- effectiv e, demonstrated solution to reduce source emissions by maximizing the productivity of more efficient and lower emission natural gas

- fired turbines in combined cycle and simple

- cycle systems. Commenters stated that analysis shows that installing TIC on ever y large existing natural gas turbine in the country could increase summertime output by 26.5 gigawatts (GW). Commenters stated that such full

- scale deployment would offer significant environmental and economic benefits:

• Commenters stated that if TIC were u sed on these turbines for just 25 percent of the year, nationwide CO2 emissions would be reduced by the equivalent of taking more than two

- million cars off the road or more than 900,000 homes off the grid annually;

• Commenters stated that ratepayers would save at least $20

- billion;

• Commenters stated that increased summertime capacity would compensate for more than 90 percent of the announced coal

- fired unit retirements.

Commenters stated that because TIC technologies increase the capacity and efficiency of relatively clean natural gas units, they believe that these technologies can and should play a key role in helping states achieve their emission targets. Commenters referred to recent analysis (Attachment) that further shows that TIC provides a demonstrat ed and cost

- effective tool to ensure continued electric reliability despite announced coal

- fired retirements. Commenters accordingly urged EPA to highlight TIC's benefits in the final rule and to clarify that TIC may serve as a compliance option for states looking to increase their reliance on natural gas combined cycle power plants.

Commenters expressed support for improving the heat rate of all power generation facilities and employing best practice environmental controls. Commenters did not believe, howe ver, that a blanket fleet

- wide heat rate improvement standard can be established in the approach used by EPA. Commenters stated that EPA may have overlooked the importance of several key factors in developing their proposed goal of 4 to 6% heat rate improv ement. Commenters recommended that EPA adopt work practice standards to establish what the best practices for improving heat rate. Commenters stated that since EPA is proposing a significant increase in the use of natural gas, they believe that best practi ces standards for heat rate need to be addressed for both combined and simple cycle gas turbines and in addition, EPA needs to look at emission limits for NOx and CO for both combined and simple cycle gas turbines.

Commenters stated that GE's Dry Low NOx ( DLN) 2.6+ combustion system for the GE 7F gas turbine incorporates advanced technology to increase combustion stability, reduce emissions and improve turndown, and extend outage intervals, thereby reducing the frequency of maintenance301 outages and improving plant availability. Commenters stated that this improved combustor can combust natural gas more efficiently, recovering more energy from the fuel with lower emissions. Commenters stated that if combined with an AGP upgrade, the improved combustor can add an additional 4 MWs for a total output gain of approximately 14 MWs (total output approximately 186 MW) and reduce CO2 by an additional 0.2 percent for a total of 2.8 percent.

Commenters stated that equipment upgrades at existing fossil fuel

- fired gas and steam turbines can significantly improve performance, reliability, and efficiency while reducing emissions. Commenters stated that examples of specific upgrade options for gas turbines include Advanced Gas Path Upgrade (AGP). Commenters stated that GE's AG P is an upgrade option available for simple and combined cycle installations within the footprint of the existing 7F gas turbine. Commenters stated that the AGP upgrade lowers fuel consumption while increasing maintenance intervals and extending the life o f parts. Commenters stated that located downstream from the combustor, the gas turbine is exposed to extremely high temperatures, so the AGP upgrade also includes improved materials and cooling technology that requires less air devoted to cooling. Commente rs stated that this allows more airflow to be devoted to making energy, thereby improving output and efficiency. Commenters stated that the AGP upgrade will also include better sealing technology so less air leaks around the turbine blades, further improvi ng efficiency. Commenters stated that overall, the AGP upgrade has the potential to add about 10 MW to output (depending on the current equipment configuration), while reducing CO2 by more than 2.6 percent.

Commenters stated that if the AGP upgrade is inst alled with GE's OpFlex Suite of software solutions, significant additional emission reductions can occur as a result of up to a 50 percent faster warm/hot start

- up time. Commenters stated that this results in up to 50 percent fewer emissions during start

- u p periods. Commenters stated that an existing 7F gas turbine with AGP technology generating a net output of 525 megawatts of power can reduce its CO2 emissions by around 11,400 tons per year, which is roughly equal to removing 2,200 cars from U.S. roads.

C ommenters stated that GE has developed and deployed a number of significant steam turbine upgrade technologies that have improved the performance, operation and reliability of steam turbines while reducing emissions. Commenters pointed to GE Energy's Advan ced Design Steam Path (ADSP) and stated that because the efficiency of a unit is largely dependent on the efficiency of the energy conversion in the steam turbine, it is important to minimize aerodynamic and steam leakage losses in the steam path. Commente rs stated that introduced in 1995, ADSP has resulted in steam path efficiency improvements ranging from 1.5 to 3 percent. Commenters stated that along with ADSP, GE has also developed advanced

- vortex designs, integral cover buckets, and brush seals that cr eate additional improvements in efficiency.

Commenters stated that the design goal of a Dense Pack retrofit is similar to ADSP; its aim is to put the most efficient steam path into an existing high

- pressure outer shell. Commenters stated that the Dense Pac k upgrade inserts new rotor and stationary components inside the existing turbine shell. Commenters stated that the resulting high efficiency steam path produces a lower heat rate and increases output for the same steam flow. Commenters stated that the Den se Pack design also has the benefit of reducing particle erosion, such that the improved efficiency is more sustainable. Commenters stated that installation of the Dense Pack Steam Path can be done during a planned outage with minimal disruption.302 Commenter s stated that heat rate improvements are an accepted metric for emissions reduction in coal

- fired plant and should be used for non

- coal fossil fuels. Commenters stated that a typical natural gas combined cycle power plant has a heat rate (i.e., the amount of fuel used per unit of electricity generation) that is about one third lower than that of a combustion turbine or gas

- fired steam turbine plant. Commenters stated that the newest NGCC systems claim efficiencies of greater than 61 percent. Commenters favo red using this metric for supporting BSER.

Commenters stated that EPA should determine the amount of emission reductions from existing NGCCs that should be included in Building Block 1. Commenters stated that EPA has excluded NGCCs from the goal

- setting ca lculations under Block 1. Commenters stated that the review of EPA's AMPD data suggests that opportunities for O&M based reductions for much of the NGCC fleet that operates at approximately 850 lbs CO2/MWh emission are smaller than for the coal

fired fleet , however, the potential for emission reductions may be significant. Commenters stated that this issue deserves far more evaluation than EPA has thus far provided.

Commenters stated that the emission profile of the Fore River Generating Station Unit Twelv e, selected at random by the Sierra Club, provides an example of the potential performance improvements that might be anticipated were EPA to conduct a full evaluation. Commenters stated that other units have shown smaller variation. Commenters stated that data reflecting the profile of the overall fleet have not been complied. Commenters provided a Figure 12 , entitled:

“ Fore River Unit Twelve Daily Average Emission Rate 2006

- 2012 ” . Commenters stated that Fore River Unit 12's emission profile is similar to that of coal

- fired units, and that the long term average performance of this unit was 831 Lb/MWh. Commenters stated that it's best annual average performance was 3.4 percent better at 803 Lb/MWh and its 95th percentile rolling annual average was 805 Lb/MWh , 3.2 percent better than it's long term average. Commenters stated that this unit's 2012 emission rate of 855 Lb/MWh is 6.7 percent higher than its 95th percentile low rolling annual average.

Commenters stated that in addition to variation in performance of "better" units, the NGCC population includes a number of very high emitting units that deserve additional scrutiny. Commenters stated that the following chart is taken from EPA's selection of "new NGCCs". Commenters stated that it is provided to illust rate the difference in performance of "better" units, shown above, and high emitting NGCCs not yet evaluated by EPA. Commenters provided a Figure 13 EPA's 600 CAMD Data Set. Commenters stated that while they have not yet fully evaluated the extent to which heat rate improvements at NGCCs should be incorporated in the Block 1 calculations, it seems clear that those calculations should include some improvements to NGCC units. Commenters stated that the technical literature concerning efficiency degradation at NGCCs suggests ongoing O&M efficiency improvements can be achieved based on enhanced turbine cleaning operation and regular turbine maintenance.

Commenters stated that in addition, the data reviewed to date shows degradation in monthly CO2 emission rates at some units that may be related to the use of the unit without the heat recovery steam generator or to some other significant malfunction, suggesting that this issue merits a detailed evaluation. Commenters provided a Figure 14 , entitled: “ West Phoenix Unit 6A Average Daily Emission Rate ” . Commenters stated that in addition to O&M improvements, there are a number of potential equipment upgrades that operators of gas

- fired combustion turbines can undertake in order to reduce emissions. Commenters stated t hat these include the following:303 • Adding heat recovery steam generators ("HRSGs") to combustion turbines that operate more than 1,200 hours per year;

• Installing inlet air chilling or cooling at units that operate at warm temperatures;

• Using inlet air chi lling or cooling preferentially to duct burners for increased power; and

• Using supplemental solar thermal units to heat the feedwater to the HRSG.

Commenters stated that accordingly, EPA should study the heat rate improvements that can achieved through e nhanced O&M practices and equipment upgrades at gas

- fired units and should incorporate these improvements into its final emission guidelines.

Commenters stated that the objective of low

- pressure service upgrades is to recover performance losses attributed to unit aging by installing advanced replacement components. Commenters stated that these components increase reliability due to their modern engineering and the reduced likelihood of corrosion. Commenters stated that use of the low

- pressure service upgrad es expand output and improve heat rate through improved low

- pressure section efficiency and reduced exhaust velocities. Commenters stated that the low

- pressure service upgrades also have the advantage of reduced maintenance costs by eliminating costly roto r repairs.

Commenters stated that as with the Section section 111(b) proposal for new sources, EPA has applied a double

- standard when evaluating potential heat rate improvement opportunities for coal

- fired units and other designated facilities. Commenters stated that although EPA discusses differences in the design, operation, age, and condition of the existing NGCC fleet, the proposed rule does not attempt to analyze whether any opportunity for improved efficiency exists, or, if so, how significant that op portunity might be. Commenters stated that it is ironic that EPA is relying on increased utilization of NGCC resources, but has ignored whether or not those units are achieving optimal efficiency. Commenters stated that based on a review of the data EPA re lied upon to propose the state goals, it is readily apparent that the efficiency and performance of the existing NGCC fleet varies significantly within individual states and across the country. Commenters provided a graph that is based on an analysis of un it

- specific emission rates, and identifies the minimum, maximum, and average NGCC CO2 emission rate for each state in 2012 (the blue line represents the range of emission rates calculated, while the red marker is the average for the state).

Commenters stat ed that a number of potential opportunities to improve the performance of NGCC have been identified that are, at a minimum, worth evaluating which includes opportunities related to turbine improvements and air cooling systems. Commenters stated that these types of opportunities and others are discussed within various technical reports, such as the following:

• "Gas Turbines: How to Improve Operability, Output and Efficiency." Cogeneration & Onsite Power Production Magazine. (2010)304 • "GE Combined Cycle Product L ine and Performance." GE Power Systems. (2000)

• Bastianen & Voeller. "Economic Considerations for Gas Turbine Power Augmentation with Inlet Cooling." Energy

- Tech.com. (2010)

Commenters stated that the bulk of the combined cycle plants EPA assumes will be op erated at higher capacity factors are relatively new, having been constructed in the past 15 years. Commenters stated that to minimize fuel costs, high efficiency is a major factor in combined cycle plant designs. Commenters stated that the design of a com bined cycle plant involves a high degree of integration between the combustion turbine, the heat recovery steam generator(s) and the steam turbine generator.

Commenters stated that EPA notes that while the potential for heat rate improvements is greater f

or coal

- fired steam EGUs, heat rate improvements have the potential to reduce CO2 emissions from "all types of affected EGUs". Commenters stated they agree. Commenters stated that EPA's second category of approaches to reduce CO2 emissions, "Building Block 2," is based on the re

dispatch of generation from higher emitting fossil fuel

- fired EGUs to less carbon intensive fossil fuel

- fired EGUs, in particular natural gas combined cycle (NGCC) units that were in operation or commenced construction as of January 8, 2014. Commenters stated that as a result of the increased role of natural gas units, EPA estimates that roughly one

- third of the overall CO2 reductions required will come from this re

- dispatch to gas.

Commenters stated that the increased role of gas

- fi red generators will result in increased demand for operational efficiency and reliability at existing units. Commenters stated that many existing
gas

- fired units were put in service years ago and, while highly efficient, have the potential for additional h eat rate improvements through the implementation of technology advancements incorporated in more recent NGCC or natural gas simple cycle turbines (SCGT). Commenters stated that to facilitate this re

- dispatch, achieve optimal performance, and to generate el ectricity in the most cost effective manner from these existing units, owners and operators will look at upgrade opportunities to improve heat rate and increase efficiency and reliability. Commenters stated that in fact, given the enhanced role of gas

- fire d EGUs will play as a result of the proposed guidelines, the opportunities for equipment upgrades and improved efficiency may be on par, and may even exceed the opportunities available with coal

- fired EGUs.

Commenters stated that there are significant opportunities for improved performance at each of the three main components of a gas turbine including: the compressor that compresses or squeezes the incoming air; the combustor that burns the fuel; and the turbine that extracts the working energy from th e exhaust gas. Commenters stated that increased efficiency will lower CO2 emissions per MWH as well as the emissions of more traditional air pollutants, such as nitrogen oxides (NOx). Commenters stated that this is an important objective of the proposed
gu idelines if the re

- dispatch of power envisioned in Building Block 2 causes individual units to generate more power.
Commenters stated that in addition to improving efficiency and lowering emissions per megawatt of electricity produced, most if not all of t he likely equipment upgrades will also improve the reliability and durability of the unit

- an important aspect that cannot be overlooked305 given their increased role in providing electricity. Commenters stated that reliability and durability of gas units wi ll be key in assuring that states can develop plans that comply with the proposed guidelines without risking service to residential, commercial, or industrial customers. Commenters stated that equipment upgrades also often involve updating controls and sof tware packages that allow for a more responsive system.

Commenters stated that the performance of existing NGCC units can be improved with the installation of more advanced compressors. Commenters stated that for instance, the 7F.05 high

efficiency gas tur bine can achieve efficiency levels of 59 percent in combined cycle mode. Commenters stated that this is due in part to the fact that the 7F.05 turbine has a more advanced compressor that is able to pass more air through the turbine and more efficiently com press the incoming air. Commenters stated that in addition to improving efficiency, implementing the 7F.05 compressor upgrade on earlier vintage 7F gas turbines will increase durability and overall gas turbine availability. Commenters stated that all of th ese features are critical for the enhanced role of existing NGCC expected under the proposed guidelines. Commenters stated that if the 7F.05 compressor upgrade is coupled with other upgrades, namely the AGP upgrade and the DLN2.6+ combustor upgrade, it can reduce CO2 emissions by an additional 3.8 percent for a total emission reduction of 6.6 percent per megawatt of electricity produced.

Commenters stated that the EPA's analyses assume that the average emission rates for the existing NGCCs will remain const ant as the output of the units increase. Commenters stated that this is a conservative assumption.

Commenters stated that the 2012 heat rates and emission rates for the NGCCs (other than the Pine Bluffs cogenerator) reflect relatively low levels of operati on. Commenters stated that in the periods in which the units operate near full power, the four plants comprising 2x1 combined

cycle blocks driven by frame turbines (GE F7A turbines at Hot Spring, Union and Dell, Siemens 501G at Magnet Cove) typically have CO2 emission rates around 820 lb/MWh (compared to emission rates of 840 to 920 lb/MWh in 2012). Commenters stated that the Oswald and Fitzhugh typically have high

- load emission rates of around 930 lb/MWh (compared to average emission rates of 1,010 to 1,13 0 lb/MWh in 2012). Commenters stated that the improvement of each plant's emission rates as output increases may be offset by the fact that the plants with the greatest opportunity for increasing output have the highest heat rates and emission rates.

Comme nters stated that the Arkansas NGCCs are all connected to the transmission system, have sufficient gas supply (as demonstrated in the previous section), and most have permits that cover their entire potential to emit. Commenters stated that for example, th e ADEQ permit for the NGCCs contain the following features:

Union Power Station: Commenters stated that the CTs are permitted for continuous operation (i.e. 8760 hr/yr) while duct burners may be fired up to 4,000 hours per year each (285 MMBtu/hr HHV). (P ermit No. 1861

- AOP

- R2 at 5)

Pine Bluff Energy Center: Commenters stated that the permit provides "The hourly emission rates...based on a worst

- case scenario" of 12 lb/hr of particulates for the first combined

- cycle set running on gas and 14.8 lb/hr for th e second set, and sets the annual emission level at 56.1 T/year (9,350 hours of operation on gas) and 66.6 T/year (9,000 hours), respectively (Permit No.1822

-306 AOP

- R1 at. 26 and 27). Commenters stated that the corresponding limits for NOx are equivalent to 9 ,000 and 15,500 full

- load gas

- fired hours. Commenters stated that the higher annual emissions limits allow for full

- load operation even with substantial use of fuel oil, which is unlikely to be economic in Arkansas.

Magnet Cove: Commenters stated that the units are expected to operate continuously (8,760 hours per year), except for maintenance and repair activities or during periods of low electrical demand. Commenters stated that the duct burners are fired to meet peak electrical demands at a maximum of 2 ,500 hours per year. Commenters stated that the annual NOx emission limit is more than 13,000 times the hourly limit (Permit No. 1987

- AOP

- R1 at 10 and 15)

Dell: Commenters stated that annual emission limits are 8,760 times the hourly limits. (Permit No. 19 03

- AOP

- R8 at 17)

Hot Spring Power: Commenters stated that the annual NOx emission limit is about 8,000 times the hourly limit) and about 14,000 times the average hourly emissions at high load.

Commenters stated that the Arkansas DEQ also expressed concern (at 12) that "Increased generation from NGCC may trigger ... PSD review due to increased emissions of other pollutants." Commenters stated that the ADEQ air permits generally allow most of the NGCCs to operate at full capacity all year long. Commenters sta ted that increased use of a facility, within existing permit levels, would only trigger PSD review if the increase were caused by a major modification or reconstruction. Commenters stated that increased operation of an NGCC due to increased economic dispat ch would not constitute a major modification. Commenters stated that the EPA Regulatory Impact Analysis notes (at 9

- 14), that in the period of analysis (through 2025) the EPA anticipates few sources will trigger either the modification or the reconstructio n provisions ... the EPA believes it unlikely that [power plants] will take actions that would constitute modifications or reconstructions as defined under the EPA's NSPS regulations.

Commenters stated that in any case, PSD review would only trigger a BACT review, and all modern NGCCs would meet BACT.

Commenters stated that even though EPA acknowledges that "heat rate improvements have the potential to reduce CO2 emissions from all types of affected EGUs," it decided "conservatively" to propose that only re ductions from coal

- fired EGUs be incorporated into the state standards. Commenters stated that EPA's principal reason for simply dismissing consideration of emission reductions from heat rate improvements ("HRI") at non

- coal

- fired EGUs was its belief that those improvements would be "relatively small." Commenters believed that conclusion cannot survive scrutiny.

Commenters stated that initially, EPA must base its decisions concerning the greenhouse gas effects of natural gas

- fired plants on accurate data, w hich requires the use of proper methane GWP and leakage rate values in the coal and natural gas lifecycle greenhouse gas emissions comparisons. Commenters stated that it must then examine the consequences of the Proposed Rule based on those corrected value s. Commenters believed it virtually certain that EPA has significantly underestimated the amount of emissions from natural gas plants on a lifecycle basis, and therefore also the amount of emission reductions that BSER can accomplish. Commenters307 stated tha t for that reason alone, EPA's conclusion that available emission reductions are small is very likely incorrect.

Comment 2: Some commenters supported the EPA’s use of the estimated heat rate improvement potential from coal

- fired EGUs alone as a reasonable approach to quantifying the total CO2 reduction potential for fossil fuel

- fired EGUs under building block 1. These commente rs supported the EPA’s position that the total CO2 reduction potential for non

- coal

- fired EGUs would be small relative to the much larger potential from coal

- fired EGUs.

Response 2: We acknowledge commenters support for our approach to quantifying the CO2 reduction potential for fossil fuel

- fired EGUs under building block 1, and have maintained the coal

- fired only aspect of our quantification approach for this final rule. For the re asons given in response to Comment 1 in this section, the Agency is focusing its resources at this time on the larger CO 2 reduction potential of affected coal

- fired EGUs.

The following are summaries of the specific public comments under this comment:

Commenters supported EPA's proposal that BSER should include heat rate improvemen ts only at coal

- fired steam EGUs, not at other EGU types. Commenters concurred with EPA's finding that "the total additional potential reduction [associated with requiring heat rate improvements at oil/gas steam EGU s and combustion turbines] is small comp ared to the potential coal

- steam CO2 reduction." Commenters agreed with EPA's conclusion for NGCCs that "[r]regularly scheduled maintenance practices are the most effective HRI methods that can be applied on NGCCs" and that they are "likely already being a pplied across most of the NGCC fleet."

Commenters stated that they support EPA's proposal that BSER should include heat rate improvements only at coal

- fired steam EGUs, not at other EGU types. Commenters agreed with EPA's finding that "the total additional potential reduction [associated with requiring heat rate improvements at oil/ gas steam EGUs and combustion turbines] is small compared to the potential coal

- steam CO2 reduction."

Commenters stated that they support EPA's determination to not include heat rate improvements

on non

- coal

- fueled units as part of BSER. Commenters stated that generally, as EPA noted, the opportunities for heat rate improvements on NGCCs and oil

- fueled units are extremely limited and the most significant improvements may result i n a unit triggering the applicability of the modified and reconstructed sources provisions of Section section 111(b) or New Source Review requirements.

Commenters stated that they agree with EPA's findings that total potential CO2 reductions achievable thr ough heat rate improvements at non coal

- fired units are small compared to the potential at coal

- fired units and should not be used in the setting of BSER. (Fed. Reg. 34877)

Commenters stated that heat rate improvements (HRIs) at other EGU types are availab le and in some cases can be cost

- effective, such as equipment upgrades on NGCCs, however, EPA would need to develop a more robust justification than it did for coal EGUs in determining achievable levels for non

- EGU HRI goals. Commenters stated that if EPA elects to allow heat rate308 improvements at other EGLI types, it should not be included in each state's goal calculation. Commenters said that states should have the flexibility to treat this as an optional measure to meet Building Block 1 goal.

Commenters s tated that each state's carbon reduction target reflects an emissions level that EPA has determined to be "reasonable" based upon application of a BSER for coal powered plants. Commenters stated that in this case, the BSER is the combination of four emissi on reduction strategies labeled in the rule as "building blocks (BB)." Commenters stated in consideration of the building blocks and their potential costs, it appears that the BSER will work for Arkansas with the initial and highest carbon emission reducti ons coming from the increased deployment of combined cycle gas turbines (CCGT)

- an emission reduction up to 30%

- or 68% of the carbon target for the state.

Commenters stated they concur that any opportunity for HRI exists at the steam turbine. Commenters noted that also the greatest loss in the performance of the combustion turbine portion of the NGCC is due to the physical degradation that occurs in proportion to its hours of operation and number of starts. Commenters noted that it has long been the prac tice of NGCC owners, including their facility, to closely follow the manufacturer's maintenance recommendations that regularly restore efficiency and reliability of the turbine. Commenters stated incentives for this practice already exist as this improves the efficiency, and hence the economic value, of the unit. Commenters noted they agree that regularly scheduled maintenance practices are the most effective HRI for these units. Commenters noted that because they are already being applied and were being ap plied by the industry in the baseline year there is no opportunity for further HRI through this rulemaking. Commenters stated they appreciate that EPA recognizes that these practices are already being employed by the industry and that additional meaningful HRI is not available for these units.

Commenters stated that significant heat rate and efficiency improvements for the natural

- gas fired steam units operated in Coffeyville and Winfield are not readily apparent either. Commenters stated that operators of these units have indicated that some slight efficiency gains might be possible by continually fine

- tuning the boiler, making burner improvements, and so forth. Commenters stated that however, any "low

- hanging fruit" is long gone and a six percent improveme nt is not realistic. Cities have made efficiency improvements over the years already as a means of providing low cost power to their customers.

Commenters stated they support the conclusion that a variability analysis for NGCC would suffer from too much un certainty that would be further compounded by a lack of available reported data. Commenters stated that because of the uncertainly and limited reported data, any conclusions about HRI for these units that would result from a "variability analysis" would no t be "adequately demonstrated" as required to support a NSPS.

Commenters stated that for the purposes of the TSD, EPA does try to gauge the potential for HRI reduction for NGCCs. Commenters stated that this was done through discussions with EPA staff famil iar with NGCC design and operation and consultation with power engineering firms and NGCC suppliers. Commenters stated that without further detail, EPA gauges that the HRI potential for NGCCs may be 2

- 3% at most on a sustained basis. Commenters noted that this HRI percentage was not informed by owners and operators of those units and may be inflated over309 what is achievable. Commenters stated that based on their experience operating these units, they believe that the HRI potential is actually less than 1%.

Commenters believed that with regards to a 2

- 3% HRI opportunity for NGCC technology, EPA's estimates are too high when considering the entire NGCC system. Commenters stated that EPA states correctly that there is little to no HRI opportunity from the combu stion cycle (or NGSC) phase of NGCC system, and that the majority of the opportunity exists in the steam phase of the units. Commenters stated that routine preventative maintenance and scheduled upgrades, as recommended 1 by the manufacturer, present the b est opportunities for HRI, a fact acknowledged by the EPA. Commenters stated that strict maintenance schedules on the units and associated subsystems are paramount for continued system reliability and unit efficiency, principles energy producers have alrea dy embraced because it makes economic sense to do so. Commenters stated that in other words, the tree has already been picked clean of its low

- hanging fruit.

Commenters stated that the EPA states that a HRI of 2

- 3% may be achieved with regard to the
steam phase of NGCCs (the HRSG, the steam turbine

- generator, and the heat rejection system). Commenters stated that they did not concur with EPA's HRI assumptions and stated that no rationale for that assumption was presented in the rule; the commenters believed that, when considering the entire system of the NGCC, the opportunity for HRI is drastically reduced. Commenters stated that for example, looking at this from an increase of capacity with burning the same amount of fuel, consider the common configuration of a 2x1 plant, where 2 x 150 MW gas turbines (combustion cycles, or NGSCs) feed hot gas to a single 180 MW steam turbine. Commenters stated that if assuming a 3% increase of output from the steam turbine, then the NGCC system, as configured, would only yi eld a little over a 1% change:

(2 x 150MW) + 180 MW = 480 MW

3% x 180 MW = 5.4 MW

5.4 MW / 480 MW = 1.125%

Commenters stated that although it was stated that NGSC usage will increase as a source of backup load in portions of the country, including Texas, a ny NGSC usage increase would not be so significant as compared to the nation's fossil fuel generation as to warrant application of HRI to these units.

Commenters stated that Golden Spread agrees with EPA's assessment of NGSC HRI as extremely small. Comment ers stated that in addition, NGSC usage is already naturally restricted by the forces of the wholesale power market except when needed to provide peaking capacity, or when the grid has reliability issues and the peaking unit in operation helps to solve tho se reliability concerns. Commenters stated that as such, and as noted by EPA, any application of HRI could only provide a minuscule reduction in CO2 emissions. Commenters stated that Golden Spread further notes that, like NGCCs, regularly scheduled mainten ance practices of the steam turbine are the most effective HRI for these NGSCs. Commenters stated that again, the industry regularly maintains these units as recommended by the manufacturer of the unit (and this practice was employed during the baseline pe riod).310 Commenters stated that EPA should not restrict the use of NGSCs, in its Proposed Existing Unit Rule, as it has done in its proposed New Unit New Source Performance Standard (New Unit NSPS) and proposed Modified and Reconstructed Unit New Source Perf ormance Standard (Modified Unit NSPS). Commenters stated that EPA's New Unit NSPS and Modified Unit NSPS applies a CO2 limitation only achievable by NGCC technology to new and modified NGSCs if they operate above a 33% capacity factor. Commenters stated th at in its Existing Unit Rule, EPA requests comments on whether heat rate improvement (HRI) from non

- coal technologies (including NGSC) should be included in Building Block 1.

Commenters stated that because wind power is quickly assuming a greater role, not just in Golden Spread's Member's service territory but throughout the country, additional generation resources will be required in order to maintain grid stability and meet load when weather conditions are not conducive to renewable energy production. Com menters stated that in fact, EPA is essentially mandating renewable energy increases in this proposed Existing Unit NSPS and as such must understand the role NGSC units play to support wind generation.

Commenters stated that NGSCs are well suited to compl ement and support wind and solar energy production because of their "fast

- start" capabilities. Commenters stated that the Southwest Power Pool (SPP) defines a "fast

- start" resource as one that can be started, synchronized and inject energy within ten minut es of notification. Commenters stated that as discussed in the testimony of Mr. George Hess, Vice President of Production for Golden Spread (please refer to Attachment 1), recent advancements in simple cycle technology have reduced the startup time to as l ittle as 70% of maximum output in 10 minutes and full power in 11 minutes on some NGSCs, from a cold state. Commenters stated that this makes NGSCs ideal for backing up wind energy.

Commenters stated that an affidavit provided by Lanny D. Nickell, Preside nt of Engineering for SPP, also discusses the quick start capability and the role these units play to support wind generation. Commenters stated that Mr. Nickell confirms that NGSCs complement variable wind generation because of their ability to start, syn chronize and inject a large portion of their energy within ten minutes of notification. Commenters stated that in fact, a review of SPP Dispatch Data from 2013

- 2014 by SPP and Golden Spread confirms a significant increase in the utilization of NGSCs sinc e the implementation of SPP's Integrated Marketplace, which also correlates with an increase in output of wind generation from 2013 to 2014. Commenters stated that SPP believes that this correlation demonstrates that NGSCs are useful in supporting variable wind in the SPP Integrated Marketplace. Commenters stated that for this reason, they urge EPA not to mandate that states include operational restrictions on NGSCs in this Existing Unit NSPS or in other NSPS standards.

Commenters stated that the proposed H RI under Building Block 1 focuses on coal

- fired EGUs and does not include HRI requirements for natural gas simple combustion (NGSC) units. Commenters agreed with EPA's rationale in this regard, particularly in view of the discussion and analysis contained in the GHG Abatement Measures Document at A

- 5

- 6 and as pointed out in that document, NGSC currently provides an extremely small amount of total fossil fuel

- fired generation

- only about 1% of the total. Commenters stated that although this percentage may i ncrease marginally if NGSC utilization increases as a source of backup load in portions of the country developing renewable generation such as wind, any NGSC increase would not be311 significant when compared to the Nation's total fossil fuel generation and, further, as EPA also points out, NGSC units cycle on and off frequently, making any attempts at implementing HRI at NGSC units largely frivolous. For these reasons, commenters support ed the Proposed Rule's exclusion of NGSC HRI from Building Block 1.

Comme nters stated that EPA indicates in the Appendix to the GHG Abatement Measures Technical Support Document (TSD), that the Agency considered potential further reductions in NGCC emissions via heat rate improvements in the existing fleet. Commenters stated th at EPA asserts that these heat rate improvements are generally undertaken as part of replacing hot gas components, and that most turbines will incorporate these improvements as part of routine maintenance.

Commenters, based experience, agreed with this gen eral conclusion. Commenters stated that existing NGCC heat rate improvements should not be included as part of BSER; nonetheless, they see the potential for EPA to unlock further improvements in gas turbine efficiency through this rule.

Commenters stated t hat GE continually invests in the development of advanced gas turbine technology. Commenters stated that the company provides a variety of gas turbine upgrade options that generally result in both increased output and improved efficiency, while maintaining or lowering emissions on a per unit of generation (MWh) basis. Commenters illustrated the evolution in GE's Frame 7F gas turbine in a figure, which shows the combined cycle heat rate (BTU/kWh) for each 7F gas turbine model, with decreasing heat rates for each model. Commenters stated that GE introduced the 7F in the early 1990s and since that introduction, GE has continually invested in improvements in both output and efficiency, resulting in today's latest offering of the GE 7F.05 gas turbine. Commenters stated that since its introduction, the 7F turbine heat rate has improved a full 8 percent, which directly correlates to a CO2 reduction of 8 percent.
Commenters stated that GE's upgrade options for their broad fleet of 7F gas turbines provide heat rate im provements ranging from 3 to 7 percent depending on the baseline turbine performance and option applicability. Commenters stated that the increased performance of upgraded turbines also flows through to the plant level performance through increased thermal energy provided to the steam turbine bottoming cycle, although these gains are more variable and subject to the bottoming cycle design.

Commenters stated that as EPA correctly notes, these upgrades are most commonly installed as part of routine major main tenance activities. Commenters stated that the gas turbine hot gas path components are subject to very high operating temperatures and high strain conditions. Commenters stated that as a result, these parts have a finite life and must be replaced on a defi ned schedule. Commenters stated that maintenance schedules are generally based on operating hours and number of starts, which varies by turbine model.

Commenters believed the average time interval between maintenance events for gas turbines will decrease b ecause of this rule. Commenters stated that EPA predicts, and they agreed, that the gas turbine fleet will become more heavily utilized. Commenters also anticipated increased deployment of gas turbines to backstop an increase in renewable resources. Commen ters stated312 that as a result, they anticipate a faster pace of upgrade installations. Commenters stated that this rule, and natural market incentives for optimal plant efficiency, will encourage owners and operators to deploy upgrades.

Commenters stated th at there are indeed significant HRI available for the gas turbine fleet, generally in the range of 3 to 7%, and they expect to see increased deployment of these technologies. Commenters stated that however, because these HRI options are typically installed as a part of routine maintenance for the operational gas turbine fleet, they agreed with EPA that NGCC heat rate improvements should not be included as part of the Agency's BSER analysis, and should not be a factor in developing state specific emission ta rgets.
Commenters stated that while GE agrees it is not appropriate to include NGCC HRI's as part of the BSER determination, these HRI options can provide significant CO2 reductions and will assist the states in meeting their individual state goals. Commen ters stated that NGCC HRI's generally result in a 3% to 7% efficiency improvement, resulting in a correlated CO2 reduction of 3% to 7% from these sources. Commenters stated that these improvements will provide direct emission benefits under this rule becau se the sources are included in state emission goals. Commenters stated that further, because these HRIs will result in reduced variable generation costs for NGCC facilities, upgraded plants will move forward in the economic dispatch queue. Commenters state d that these facilities will experience increased hours of operation as a result of market forces, bringing the NGCC fleet closer to the Agency's 70% utilization goal, reducing the cost of achieving this objective.

Commenters agreed with EPA's conclusion f or NGCC EGUs that "[r]egularly scheduled maintenance practices are the most effective heat rate improvement methods that can be applied on NGCCs" and that they are "likely already being applied across most of the NGCC fleet."

Commenters stated that the Cit y of Coffeyville feels this to be unrealistic, whereas their unit/units already only fire natural gas. Commenters stated that heat rate improvement is constantly strived for, because it equates to savings to their customers, by lowering energy cost. Commen ters stated that since the new Southwest Power Pool's Day

- Ahead Market, and dispatching based on cost of units across the SPP footprint, they have found that when dispatching the unit at minimum load, the unit heat rate is at its worst. Commenters stated t hat taking these issues into consideration, it is not likely that any improvement to heat rate can ever be achieved.

Commenters stated that in its proposal, EPA seeks comment on including heat rate improvement opportunities at other EGU types in its determ ination of BSER.16 Commenters recommended EPA not to include heat rate improvement opportunities at other EGU types (namely NGCC) because the potential for these opportunities at non

- coal fueled resources is very limited and unlikely to be economically jus tified. Commenters stated that for natural gas

- fueled NGCCs, the result of PacifiCorp's review of these opportunities with major equipment suppliers is that they require major combustion turbine component replacements, downstream system design modification s, and typically increase the capacity of the facility in greater proportion to the underlying efficiency improvement, thus potentially triggering environmental permitting requirements. Commenters stated that depending on the underlying combustion turbine type, model, and vintage, the best case heat rate improvements an NGCC plant may be able to achieve313 is 0.75

- 1.5 percent, if these major modifications could be economically justified. Commenters stated that as a consequence of the U.S. NGCC fleet's relative ly young age and advanced design, the potential for justifying material heat rate improvement projects on these facilities is likely to be very small and should not be broadly applied as a component of BSER.

Commenters stated that in its proposal, EPA seek s comment on including heat rate improvement opportunities at other EGU types in the basis for supporting BSER. Commenters concluded that, for the most part, the level of heat rate improvement opportunities at non

- coal fueled resources is limited and the p otential modifications to make those improvements will not be economically justified. Commenters stated that in some instances, de minimis heat rate improvements of less than 1% may be possible; however, these would entail significant, capital

- intensive

mo difications to the prime movers, principally the combustion turbines. Commenters stated that driven by natural gas costs, utility owners of natural gas

- fired combined cycle facilities are already fully incented to exercise best operating practices, particu larly as they pertain to unit performance.

Commenters stated that efficiency improvements in combined cycle plants are fundamentally achieved through improvements in the combustion turbine. Commenters stated that as a retrofit option, upgrading a combustio n turbine requires a flow path redesign (new blade internals), hot gas path component replacements, and in some cases may require partial or total casing replacements, exhaust cylinder replacements and rotor replacements. Commenters stated that in the even t these upgrades also result in an increase in power output and exhaust gas temperature, then a complete evaluation of all downstream components is needed and this would include a review of the heat recovery steam generator and the steam turbine to determi ne if the downstream systems can accommodate the changes in gas flow. Commenters stated that the potential to increase the power output would require evaluation of the need to replace the generator and step up transformers. Lastly, commenters stated these upgrades typically increase the size of the combined cycle plant in greater proportion to the underlying efficiency improvement; as a result, total emissions can increase which may then require re

- permitting the facility. Commenters also stated that the ai r emissions modeling review would be subject to New Source Review requirements which are performed to substantially higher emissions standards than those that were used when the plant was originally permitted.

Commenters stated that as a consequence of the U.S. natural gas combined cycle fleet's relative young age and advanced design, the potential for cost

- effectively improving the heat rates of these facilities is likely to be very limited and such requirements are not recommended in the final rule.

Comme nters stated that EPA does not explain why geographically isolated units have more potential for HRI. Commenters stated in their comments that they are not aware of why isolated jurisdictions would have more HRI potential for NGCCs and NGSCs. Commenters st ated that moreover, NGCCs and NGSCs (whether geographically isolated or not) should not be subject to Building Block 1 HRI.314 Comment 3: Commenters stated that the proposed rule does not require any increase in efficiency at existing natural gas

- fired EGUs, and thus fails to implement the technology

- forcing requirements of the Clean Air Act.

Response 3: The EPA disagrees. Please see preamb le sections V.A and V.B. for a discussion of the agency’s interpretation of the Clean Air Act’s intentions regarding technology

- forcing and the agency’s application of those intentions in this CPP final rule.

The following are summaries of the specific pub lic comments under this comment:

Commenters stated that like the earlier rule for new power plants, this draft rule doesn't require any increase in efficiency at existing natural gas plants and, thus, fails to implement the technology

- forcing requirements of the Clean Air Act.

Comment 4: Some commenters recommended that existing simple

- cycle combustion turbines should be covered by the CPP final rule.

Response 4: The EPA disagrees. Simple cycle combustion turbines are not included in this final rule for t he reasons discussed in section IV.D of the final rule preamble of the CPP.

The following are summaries of the specific public comments under this comment:

Commenters stated that EPA specifically proposes not to establish BSER for natural gas

- fired simple cycle or combined

- cycle combustion turbines because, according to the agency, by 2020 they will provide no more than 2% of total coal

- steam CO2 emissions and that BSER for them would contribute less than 1% in emission reductions. Commenters stated that em issions from simple cycle plants, however, are not trivial. Commenters stated that according to EPA capacity factor data available in the docket for the section 111(b) power plant proposal, CO2 emissions from existing simple cycle plants totaled 22,679,318 short tons (nearly 20.6 million metric tons) in 2011 alone. Commenters stated that moreover, simple cycle emissions may well increase over the next eight years to firm and support increasing amounts of intermittent renewable generation. Commenters stated that in light of the claimed relationship between increases in renewable energy and an increasing need for existing CTs, it is crucial that EPA designate BSER for these plants.

Commenters stated that the evidence in EPA's possession shows not only that sim ple

- cycle and combined

- cycle as turbines will continue to be needed, but also that this part of the power sector is anticipated to grow as coal

- to

- gas dispatching increases. Commenters stated that in light of that evidence, simply dismissing the contributi on of these plants provides no rational basis or adequate explanation for its decision not to establish BSER for simple cycle plants.

Commenters incorporated the comments by Sierra Club in this docket that discuss the need for EPA to determine BSER for the se plant categories. Commenters stated that specifically, Sierra Club urges EPA to investigate the potential to reduce emissions from a number of equipment upgrades, including heat recovery steam generators, installing inlet air chilling or cooling at unit s that operate at warm temperatures, using inlet air chilling or cooling preferentially to duct315 burners for increased power, and using supplemental solar thermal units to heat the feedwater to the heat recovery steam generators. Commenters stated that the result of EPA's analysis should be added to strengthen the overall BSER target for Block 1.

Commenters noted that, in its proposal for section section 111(b) standards for new power plants, EPA created various other loopholes and exemptions for subcategori es of natural gas

- fired plants based on their size, capacity, and the amount of their electricity sales to the grid. Commenters stated that EPA has made no such distinctions here, dismissing natural gas plants wholesale. Commenters stated that however, as EPA reconsiders its preliminary conclusion not to set establish section 111(d) targets for natural gas plants in response to the instant comments and those from other parties, they urge the agency to revisit these section section 111(b) loopholes and exemp tions, and instead establish BSER for these excluded categories in the final section section 111(b) and the instant section 111(d) rulemaking as well.

3.11 POTENTIAL EMISS ION REDUCTION MEASUR ES NOT USED TO SET PROPOSED GOALS

This section discusses comments related to alternative but acceptable potential emission reduction measures that were not included in the BSER for goal setting purposes but which states may choose to implement.

Commenters have raised a number of issues re lated to the subsection which are organized by topics (comments) below. Responses are also provided for these topics. (Below the response, comment summaries are noted.)

Comment 1 : Alternative approach

– ultra

- supercritical plant designs

Response 1 : New fo ssil fuel

- fired EGUs are covered by the CAA Section section 111(b) final rule for new sources. The section section 111(b) rule for new source performance standards looks at available technologies and their cost and performance characteristics to determine the Best System of Emission Reductions (BSER). This final CAA section 111(d) rule applies to existing EGUs only. See Applicability section II of the preamble.

The following are summaries of the specific public comments under this c omment :

Commenters stated they believe that the EPA could have achieved similar reductions in CO 2 emissions by encouraging the power generation industry into building new coal

- fired generation that has the latest advances in thermodynamic cycle efficiency and emissions. Commenters stated that IEA reports that the present average efficiency of the worldwide coal fleet is about 30% (11,400 BTU/KWhr) and the average here in the US is slightly better at around 32% (10,700 BTU/KWhr) including all coal plant designs, both sub and supercr itical firing and a variety of coal types from high BTU content bituminous coal to Texas and North Dakota lignite fuels. Commenters stated that the majority of coal plants in the US were built between 1960 and316 1980 and were a mix of sub and supercritical d esigns and that the average age of coal plants in the US is now about 45 years.

Commenters stated that higher efficiency supercritical steam cycles became available in the 1960s and the decision as to which type of steam cycle, subcritical or the higher e fficiency supercritical cycle would be used was primarily dependent on fuel cost and the risk tolerance of the user for the then new supercritical technology. Commenters stated that while numerous supercritical plants were built in the 1960s and 1970s, ope rating issues and the higher maintenance expense offset the benefits of higher efficiency and subcritical designs came back in favor in the 70s.

Commenters stated that over the past 20 years advances in supercritical boiler designs, primarily spiral wound furnaces that allow for sliding pressure operation and improvements in boiler and combustion controls that makes operation of supercritical plants much simpler, have established supercritical designs as the choice for new plants today. Commenters stated t hat improvements in materials have allowed for increases in steam temperatures and pressures resulting in even higher plant efficiencies on the newest plants (ultra

- supercritical cycles). Commenters stated that a consortium of US equipment manufacturers an d material suppliers have for several years now been working on the development of Advanced ultra

- supercritical designs using nickel based alloys that could improve pulverized coal plant heat rates by 15% or more over ultra

- supercritical designs.

Commente rs stated that replacing existing sub and supercritical coal plants with ultra

supercritical plant designs would, improve plant heat rates by 5.5

- 16% with an equivalent reduction in CO 2 emitted per MWhr produced. Commenters stated that ultra

- supercritical steam plants are a proven and commercially available product that can be provided by a number of boiler and steam turbine suppliers. Commenters stated that geographic location, fuel used and the type of condenser cooling will impact the total efficiency of any plant design but regardless of operating conditions, super or ultra

- supercritical plants would still provide a significant reduction in CO 2 emissions without the use of yet

- to

- be

- proven CO 2 capture systems.
Commenters presented for comparison some ex amples of coal plant efficiencies and CO 2 emissions for a 600MW unit operating at high capacity factor, using the various steam cycle designs, firing a sub

- bituminous coal with wet condenser cooling.

Commenters stated that as indicated by the chart include d in their comments, replacing sub

critical plant designs with ultra

- supercritical systems would reduce CO 2 emission by about 16% and if Advanced ultra

- supercritical plants can be commercialized an almost 30% reduction in CO 2 emissions per MWhr could be re alized over subcritical plants.

Commenters stated that China has been on a program to replace relatively new (<20 year old) subcritical plants with more efficient supercritical plants just to reduce the consumption of their very valuable coal reserves and that while reducing coal consumption is an important factor in the decision to replace these older designs, CO 2 emissions as well as emissions of SOx, NOx, mercury and particulates are also reduced. Commenters stated that China will also be commissioning ultra

- supercritical plants in the near future that will improve plant efficiency and reduce coal consumption and air emissions even further.317 Commenters stated that replacing aging coal plants with more efficient ultra

- supercritical plants would allow for a significant reduction in CO 2 emissions from the power generation sector and that these plant designs are commercially available today at reasonable cost. Commenters stated that these designs could be deployed in a CO 2 capture ready condition and CO 2 emis sions could be reduce now while waiting for cost effective CO 2 capture technologies to be developed. Commenters stated that given the present cost to capture CO 2 no new coal plants will be built if CO 2 capture is a requirement. Commenters stated that this valuable energy resource, coal, will be lost or exported to other countries where it will likely be used in much less efficient and less environmentally friendly plant designs and that if we are truly interested in our energy security and independence from foreign energy sources we cannot abandon coal as a power generation option.

Comment 2: Comments in support of inclusion of CHP/cogeneration

Response 2: Certain types of CHP are allowable measures for adjusting affected EGU CO2 emission rates in rate

- based state plans and is discussed in more detail in the preamble section VIII.K. The treatment of CHP retrofits at affected EGUs is addressed in section VIII.I of the preamble.

The following are summaries of the specific public comments under this co mment:

Commenters stated that this is a very important option and urged the inclusion of these to displace kilowatt hours from major power plants. Commenter s stated this is important and it also helps resiliency of the agents. Commenter s stated that this option combined with power to distribute and generation and then fuel substitution at the engine site is very, very critical to help the states meet their CO2 reduction and kilowatt hour reduction goals.

Comment 3: The EPA needs to add ress the carbon implications of particular feedstocks.

Response 3: A discussion regarding the use of some biomass feedstocks for compliance purposes can be found in Section VIII.I.2.c and Section VIII.K.1 of the preamble.

A discussion regarding the curren t status of the development of the revised Framework and how information from the revised Framework and the related peer review processes could be used to inform how states and EPA assess biogenic CO 2 can be found in Section VIII.I.2.c and Section VIII.K.1 . For more information regarding the Framework , see: http://epa.gov/climatechange/ghgemissions/biogenic

- emissions.html

The following are summaries of the specific public comments under this comment:

Commenters argued that state sustainable forestry program s or third party forestry programs do not address the carbon implications of using forest feedstocks for burning in bioenergy plants and that any sustainability standard needs to include a rigorous carbon accounting to ensure that biomass energy produced f rom forest feedstocks will reduce CO2 emissions. Commenters urged318 EPA to ensure that high

- CO2 biomass feedstocks are not harvested to power electric generating units in the U.S. and further argues that EPA needs to take a leadership role in convincing the EU and UK that they too must adopt carbon accounting standards that require identification of climate

- beneficial biomass and exclusion of climate

- harmful biomass. As an example, commenters described concerns with the use of mature bottomland hardwood fores ts in the Southeast U.S. as a biomass feedstock. Commenters also argued that EPA's carbon accounting framework should require identification of climate

- beneficial biomass that ensures that only biomass that reduces atmospheric carbon over the next 10

- 20 years qualifies under the CPP.

Commenters agreed with the inclusion of renewable energy (RE) generation as an element of the BSER, but oppose EPA's assumption that burning biomass does not lead to carbon dioxide emissions. Commenters argued that this assum ption and EPA's proposed approach regarding biomass energy contradicts scientific consensus, the analysis and recommendations made by an expert panel convened by EPA's Science Advisory board, and statements made by EPA elsewhere. Commenters included specif ic references to support their argument and noted that the assumption of carbon neutrality when evaluating the merits of biomass energy under the EU and UK renewable energy targets has resulted in consequences for U.S. forests and atmospheric carbon and th at important carbon sinks are being harvested and burned as wood pellets causing significant increases, rather than decreased, in carbon dioxide to the atmosphere from the energy
sector. Several commenters provided general comments on potential alternative measures. The following group of comments address the range of measures that should be included in the final rule and additional detail on individual measures. Note that several of these measures are discussed more fully in later sections.

Comment 4: States should be free to include measures they deem appropriate.

Response 4: A range of non

- BSER measures are not used in calculating the CO 2 emission performance rates in the final emission guidelines

— both at the affected EGU and beyond. The final rule gi ves states the flexibility, to use zero

- and low

- emitting resources to achieve their CO 2 emission performance rate. The measures discussed in the preamble are representative of those that states may consider in their plans, but are not meant to be exhausti ve.
Renewable energy and demand

- side EE and other non

- BSER measures that are tied to a state plan and achieve quantified and verified MWh savings may be used to adjust a CO 2 emission rate, provided they meet the general and specific eligibility requirement s for resources used to adjust a CO 2 emission rate, described in Section VIII.K. The measures must also meet the eligibility requirements and provisions related to RE and demand

- side EE programs and projects, if applicable, and the requirements and criteri a related to proper quantification and verification of MWhs from demand

- side EE savings are described in Section VIII.K.. Specifically, the use of biomass, MSW, and waste to energy are discussed in the preamble in section VIII.I and VIII.K. Preamble sectio n VIII.K discusses measures, such as vehicle electrification, that may not be used to adjust CO 2 emission rates.

Provisions to encourage early action are discussed in the preamble in section VIII.B.319 The following are summaries of the specific public comme nts under this comment:

Commenters said that states should be free to include a broad range of measures as they deem appropriate. Commenters were concerned that since the current proposed rule specifically mentions some measures and not others, there is a risk that if the final rule does not include a more comprehensive list of carbon reduction measures, the EPA will inadvertently send a signal to states and investors that certain unmentioned measures are not preferred mitigation measures. Commenters added that the list of measures listed at 79 FR 34923 must be considered illustrative, not exhaustive.

Commenters supported a BSER that incorporates all four building blocks, including measures at the EGU and outside of the EGU, because this approach provides t he greatest degree of flexibility and allows for the incorporation, as appropriate, of available tools to achieve greenhouse gas emission reductions. Commenters stressed that the EPA should not include additional Building Blocks as BSER, because this would make the goals more stringent while simultaneously reducing state compliance flexibility. Commenters said if EPA considers additional elements in defining the BSER, significant new analysis would be required regarding costs and benefits.

Commenters said t hat the CAA mandates that the EPA determine the BSER for purposes of setting the source

- specific emission reduction requirement under CAA Section 111(d) by looking at a specific set of sources. However, commenters stated, the CAA does not mandate that stat es are limited to requiring sources to comply with that requirement by applying only the technologies that were the basis of the BSER determination. Instead, commenters said, states are encouraged to apply other controls and techniques in their plans to me et the standards. No matter how EPA ultimately decides to set BSER, commenters concluded that measureable, reportable and verifiable emissions reductions from innovative technologies, such as combusting MSW

derived fuels like ABFuel, should be allowed to b e included as a compliance tool for States.

Commenters supported the EPA's proposal that "[s]tates may include measures in their plans beyond those that the EPA included in its determination of the BSER." Commenters stressed that these should include non

- B SER measures both identified by the EPA in the proposal and those not specifically included in an approvable state compliance plan.

Commenters also supported a wide range of measures and added that these measures should be credited with a full generation replacement; i.e., one megawatt generated by one of these measures should receive full credit as one MW of RE. Commenters said all of these measures result in lower CO 2 emissions and meet the intent and objective of the proposed rule. Commenters said that gas conversion should also be considered as part of the BSER because of the obvious co

- benefits with gas conversion resulting in the reduction of both criteria and hazardous air pollutants. Commenters added that gas conversion of a coal

- fired boiler will not result in a 40 percent CO 2 reduction as would replacement with a new NGCC unit because conversion of an existing boiler designed to burn coal will be inherently less efficient due to combustion zone and heat transfer design.

Commenters said that BSER s hould start with a focus on "inside the fence measures" and measures that can be taken at EGUs. Then, commenters said, sources should be able to opt to use320 outside the fence measures to facilitate compliance such as renewable energy and energy efficiency.

Commenters argued that the EPA's Proposal violates its authority to promulgate emission guidelines for existing sources already included within a properly listed source category (for which performance standards for new affected sources have already been es tablished). Commenters noted that the EPA's approach in this Proposal of basing its guidelines almost exclusively on "outside

- the

- fence" measures that cannot be incorporated or achieved by individual units renders the entire Proposal unlawful, and repropos al is required to address this fatal flaw. Of all the measures proposed by the EPA as possible means to achieve its state performance goal targets themselves (which are not authorized under the statute), commenters continued, only Building Block 1 is allow ed for consideration by EPA as it establishes its guidelines for existing source types. Commenters added if the EPA continues to insist on this approach, The n it should extend to the States maximum flexibility in meeting the target CO2 rates. Furthermore, commenters said the EPA should consider addressing explicitly all available

measures

- which the commenters believe should include any approach (appropriately measured and verified) that reduces or offsets CO2 emissions at regulated EGUs

- in the final rul e so as to clarify the measures states can apply in demonstrating the suitability of their section 111(d) plans. Commenters said the measures appropriate for State consideration include (but are not limited to) the following: Carbon tax; CO2 offsets; Elect rification; Biomass; Coal Drying.

Commenters said that the proposed rule should encourage states to earn credit for emissions reductions achieved by existing programs and measures after the start of program in 2020 and recommended that the EPA examine feas ible methods to provide states credit for reductions that occur prior to the start of the program while maintaining the stringency and environmental integrity of the EPA's 2030 goals.

Comment 5: General remarks on compliance options not listed in the prop osed rule.

Response 5: In the final rule, the EPA recognizes the value of renewable energy as part of the BSER and energy efficiency as a low cost resource that can reduce CO 2 emissions from affected

sources. Demand

- side EE and other non

- BSER measures are not used in calculating the CO 2 emission performance rates in the final emission guidelines

— both at the affected EGU and beyond. The final rule gives states the flexibility, to use zero

- and low

- emitting resources to achieve their CO 2 emission performance rate. The measures discussed in the preamble are representative of those that states may consider in their plans, but are not meant to be exhaustive.

Renewable energy and demand

- side EE and other non

- BSER measures that are tied to a state plan and achieve quantified and verified MWh savings may be used to adjust a CO 2 emission rate, provided they meet the general and specific eligibility requirements for resources used to adjust a CO 2 emission rate, described in Section VIII.K. The preamble mentions a numbe r of specific allowable measures that commenters asked the EPA to consider including energy efficiency, transmission and distribution improvements, CHP, nuclear power, hydroelectric power, and biomass. Preamble section VIII.K discuss measures, such as CO 2 emission reductions from outside of the power sector that may not be used to adjust CO 2 emission rates.321 The measures must also meet the eligibility requirements and provisions related to demand

- side EE programs and projects, if applicable, and the requirem ents and criteria related to proper quantification and verification of MWhs from demand

- side EE savings are described in Section VIII.K.

Commenters in this section supported the inclusion of biomass

- derived fuels as a compliance option, and noted that the EPA should clarify the role of biomass in complying with targets. Some commenters also specifically supported waste

- to

- energy as a compliance option. A discussion regarding the use of some biomass feedstocks, including waste

- to

- energy, for compliance purp oses can be found in VIII.I and Section VIII.K of the preamble.

The following are summaries of the specific public comments under this comment:

Commenters stressed that availability of clean energy solutions like energy efficiency, and wind and solar energ y are available and affordable. Commenters added that national and utility

- scale modeling as well as actual experience is showing that very substantial cuts in greenhouse gases can be made in the electric utility sector

- on the order of 40% or 50%

- witho ut sacrificing reliability or affordability, and while providing other environmental benefits like reduced acids, heavy metals, and particulates in our air and water. Commenters also supported guidance in the final rule for incorporating alternative measur es such as energy efficiency and renewable energy.

Commenters said that the EPA's suggested compliance options do not represent the full array of tools available to states, and tools such as bolstering energy efficiency in the built environment, renewable energy, and waste utilization for energy are not given adequate attention in the proposed rule. Commenters stated that actions taken by communities to adapt to climate change and become more resilient should also be encouraged by the proposed Clean Power P lan when they help lower greenhouse gas emissions. Commenters noted that climate adaptation measures offer significant cost savings by making communities less vulnerable to the extreme weather events and heat waves made more frequent by climate change.

Com menters said that additional measures should include, but not be limited to: electricity transmission and distribution efficiency improvements; retrofitting affected EGUs with partial CCS; using biomass

- derived fuels at affected EGUs; co

- firing with natura l gas at affected EGUs; using new NGCCs, new nuclear, uprates at existing nuclear, in

- state and out

- of

- state renewable energy credits, new hydropower, and incremental hydropower at existing facilities. Commenters particularly supported managing waste in wa ste

- to

- energy facilities instead of landfills, while commenters said that the EPA should recognize distributed generation and similar emerging technologies as eligible resources.

Commenters added that the EPA should also allow states and utilities to recei ve savings credits for a wide variety of energy programs, including but not limited to measures based incentives, behavior change programs, transmission and distribution system upgrades, financing programs, and incentives for combined heat and power (CHP).

Commenters said that for states where the majority of the electricity comes from coal

- fired generation, as described in the example for the State of Wyoming, they had concerns that the proposed rule will result in a significant increase in electrical rate s and potential disruption of322 electricity delivery. Instead of the approach found in the proposed rule, commenters recommended a focus on energy conservation and combined heat and power projects. Commenters stated such methods allow for a more efficient us e of existing resources that will result in lower greenhouse gas emissions without a significant increase in rates and the risk to the reliability of the electrical grid.

Commenters also supported including energy efficiency policies and programs, as well as renewable energy and other low/no

- carbon generation options, in state 111(d) implementation plans. Under this approach, commenters said that electrical energy savings attributed to state

level energy efficiency resource standards (EERS) and utility effi ciency programs, enhanced building energy codes, state and local incentives and other measures could be credited for avoided power plant emissions and count toward meeting power plant 111(d) standards.

Commenters said that rather than creating a scenario i n which compliance with meager targets can be achieved with limited and in some cases no additional effort, the rule should require aggressive action by all states on every front. Commenters recommended that the rule should require that SIPs include effici ency (heat

- to

- electricity transfer rate) improvements at all fuel

burning power plants (both coal and gas facilities) and maximize the development of zero

emission renewables.

Commenters encouraged the Agency to support strategies that are performance

- base d and technology neutral, because these approaches are the best way to encourage the innovative and environmentally responsible energy production necessary to meet the nation's current and future electricity needs while aligning with emission reduction goa ls. Commenters added that policymakers and energy providers must recognize that a technology

- neutral, performance

- based environment that encourages innovation and competition will increase cost

- effective, carbon

- free power contributions to the energy mix. Commenters stated that is feasible and cost

- effective to reduce carbon emission to much lower levels without relying on new natural gas or nuclear
energy.
Commenters said that the EPA should clarify that renewable energy technologies using fuels, such as g eothermal, landfill methane gas, pumped storage hydropower, dairy digester gas, biogas, and biomass, are eligible for compliance as well as solar thermal, natural gas energy efficiency and tree planting programs. Commenters added that sunlight is abundant all over the globe and available for power generation using current technologies as amply illustrated by Germany's performance.

Commenters said that other compliance issues that the EPA should provide clarity on in the final guidelines include broadly defi ning the types of "corrective measures" that states could include in compliance plans to include methane reductions from natural gas distribution systems. Commenters added that the EPA also should affirm the importance of electrification in reducing CO2 em issions from other sectors, and make clear that states will not be penalized under section 111(d) as a result of these efforts.

Commenters said that examples of acceptable measures include planting of native prairie as a method of natural carbon sequestrat ion, state actions incenting energy efficiency improvements323 in rental properties, expansion of methane extraction from sanitary landfills, and additional renewable energy such as biomass and solid waste burning.

Comment 6: Allow emissions reductions resul ting from utility's programs to count towards compliance.

Response 6: CO 2 emission reductions resulting from a utility’s programs may be considered in state plans, as long as they meet the criteria in the State Plans section of the preamble. Allowable

meas ures must reduce CO 2 emissions from affected EGUs. A program that reduces CO 2 emissions from outside the electric power sector may not be approvable as part of a state plan under this CAA section 111(d) rule. See section VIII.D and VIII.K of the preamble f or more on state plan requirements.

The following are summaries of the specific public comments under this comment:

Commenters said that the Agency should also allow emissions reductions resulting from programs between utilities and their customers, such a s the beneficial use of fly ash from power plants used in the manufacture of cement (reducing cement plant costs, as well as CO2), to count toward compliance with a state plan.

Comment 7: Commenters supported biomass as an option for meeting renewable goals.

Response 7: Several commenters supported the use of biomass as a compliance option for meeting the EG goals. Many commenters mentioned benefits from biomass power, some environmental, some economic (e.g., the economic benefits of a biomass

- based economy), some in terms of broad co

- benefits. Some commenters pointed specifically to the carbon and environmental benefits of sustainably produced biomass; one noted the presence state programs that provide a framework for monitoring forest sustainability, and another supported the use of existing methods to quantify GHG emissions reductions. Some commenters supported specifically the inclusion of biomass from residues and waste streams.

A disc ussion regarding the use of some biomass feedstocks, including waste

- to

- energy, for compliance purposes can be found in VIII.I.2.c and Section VIII.K.1 of the preamble.

A discussion regarding sustainably

- derived biomass feedstocks can be found in Section V III.I.2.c of the preamble.

The following are summaries of the specific public comments under this comment:

Commenters stated that the EPA's recent release of the Framework for Assessing Biogenic CO2 Emissions from Stationary Sources recognizes the importan t role that using "waste

- derived feedstocks" as well as "forest

- derived industrial by

- products" can play in the low

- carbon economy. Commenters continued by demonstrating how biomass is already being integrated into the electric grid.324 Commenters stated tha t biomass power can be derived from both waste and purpose

- grown biomass crops, and that current supply of waste feed in the US is 244 million dry tons of sustainably recoverable agricultural wastes. Biomass power is a full 22 percent of the US's renewable energy supply, and the commenters requested that currently available resources be adequately addressed by the proposed Clean Power Plan.

Commenters also noted that biomass power has economic and environmental co

- benefits, as
proper crop rotation for purpose

- grown biomass can replenish soil nutrients and increase soil organic content levels. Commenters stated biomass power and waste

- to

- energ y can provide local jobs, additional revenue to municipalities, and partially address the issues of overflowing landfills and growing waste streams.

Commenters stated that the EPA should recognize biomass as a renewable energy because most states with a R enewable Portfolio Standard recognize biomass energy, however these states treat biomass energy unequally to other renewables. Therefore, the commenters recommended that the EPA:

• Recognize that sustainable woody biomass harvesting (especially waste utiliza tion) does not increase net carbon accumulation, as long as overall forest stocks are stable or increasing.

• Recognize thermal heat in the Clean Power Plan. Thermal energy represents 40 percent of energy used In the U.S. and its omission skews recognition o f the emissions for this use of energy.

• Build upon the programs and work occurring in the agriculture and forestry sectors at the state level, which have already defined and developed sustainable practices for biomass harvesting.

• The category of "waste

- der ived materials" should be inclusive of the significant organic waste streams created in the United States. The Clean Power Plan should incentivize the use of these organic wastes (including manure, landfill, organic, food waste) for the generation of elect ricity.

Commenters stated that proper management of agricultural residues, forest management and wood processing residues, biomass waste, and energy crops could ensure the effective utilization of biomass co

- firing to reduce CO2 emissions. Commenters stat ed these sources can be quickly

re

- sequestered and are more energy dense than other biofuel feedstocks. Commenters believed that if properly utilized these resources could offset up to 273 million tons of CO2 annually.

Commenters expressed support for the inclusion of biomass. Commenters expressed pleasure at the recognition of the carbon and climate benefits of biogenic feedstocks, and commenters stated that this was the recognition of the common sense approach and the growing body of scientific findings c oncluding that carbon emissions from biomass do not introduce new carbon into the existing carbon cycle and can thus be considered by states in their SIPs. Commenters stated that biomass will give states increased flexibility in meeting the proposed emissi ons reductions. Commenters stated that Georgia has a program in place to monitor the sustainability of the forest325 resource, including the Georgia Forestry Commission's Forest Sustainability Report, Forest Inventory and Analysis (FIA) and forestry Best Mana gement Practices (BMPs).

Commenters stated that biomass can supply increasing amounts of low carbon electricity if developed in a sustainable manner. Commenters referenced NREL, EIA, and UCS modeling results which demonstrated biomass co

- firing to be a cos t

- effect option and to represent a portion of renewable energy expected to come on line by 2030. Commenters acknowledged that the source of the biomass is critical to ensuring that the co

- firing decreases total CO2 emissions on a lifecycle basis. Commenter s stated that cost estimates for this practice are highly site

- specific and may be driven by many factors including collection and transportation costs and the distance the feedstock must be transported. Commenters suggested that biomass co

- firing be evalu ated on a regional or state basis for BSER inclusion. Commenters stated that biomass co

- firing can help to stimulate local and regional economies, especially in the Midwest, the Southeast, and Appalachia.

Commenters expressed support for the use of biomass derived feedstocks pointing to benefits from its use. Commenters noted that the use of renewable biomass feedstocks displaces the amount of traditional fuel and products made from fossil fuels. Commenters noted that the biobased manufacturing process ofte n generates co

- products that can either displace or enhance fossil fuels. Commenters also noted that the biobased economic sector is creating jobs and enhancing energy and national securing using home

- grown feedstocks to produce biofuel. Commenters stated that the EPA should encourage states to include the use of biomass derived fuels in their state plans, and the EPA should provide the most specific guidance possible on the inclusion of these measures in a state plan.

Some commenters described the benefits of co

- firing innovative non

- waste fuels in addition to
waste

- derived biomass fuels.

Commenters said that in order to allow states to deploy scientifically

- sound emissions reductions quantifications in the time required for promulgating SIPs, the EPA shoul d allow States to use existing emission reduction methodologies and protocols (e.g., offset methodologies) to quantify GHG emissions reductions. Commenters stated that states will see additional benefits through using existing methodologies when evaluating the emissions reductions of technologies like ABFuelTM, which have multiple streams of benefits that are challenging to calculate. As developing a new quantification methodology may take many years, commenters said that the EPA should not prevent states f rom recognizing the benefits of waste

- derived biomass

- based fuels to be gained by using scientifically sound methodologies that will be available as the states are developing their emissions reductions plans. Commenters added that the EPA should allow Stat es to credit the full range of GHG emissions reductions associated with innovative non

- waste fuels like RePower South's ABFuelTM, including emissions reductions made prior to 2020. Commenters stated that co

- firing ABFuelTM with coal generates significant r eductions of GHG emissions, and the EPA should structure the Clean Power Plan to encourage emissions reductions, including those from the co

- firing of ABFuelTM and similar fuels. Commenters concluded these reductions occur both on site and outside the fenc e of the generator, and include reductions from decreased organic matter in landfills, displaced coal, and increased recycling.326 Commenters referred to the revised Framework for Assessing Biogenic CO2 Emissions from Stationary Sources ("Revised Framework") released by EPA on November 19, 2014, which EPA intends to submit to the SAB for further peer review and to the memorandum to EPA's Air Division Directors confirming its commitment to recognize the climate benefits of biomass energy through its administrat ion of the Clean Air Act. Commenters noted that, in the memo, EPA recognizes "the critical role that America's forests play in addressing carbon pollution in the United States," and explained how it intends to incorporate biomass energy into existing Clean Air Act programs addressing climate change. With respect to this rulemaking, commenters noted that EPA first recognizes "the biogenic CO2 emissions and climate policy benefits of waste

derived and certain forest

- derived industrial byproduct feedstocks." C ommenters noted that, more broadly, EPA recognizes that States have already taken the lead in recognizing the climate benefits of a wide range of biomass materials including forest

- derived biomass, and explains its expectation that "states' reliance specif ically on sustainably

- derived agricultural

- and forest

derived feedstocks may also be an approvable element of their compliance plans." Commenters stated that together these statements from EPA confirm the critical role that biomass energy can play in miti gating carbon emissions from the electricity sector

. Regarding regulation of biomass energy, commenters supported the comments by NAFO and by the AWC (with AF&PA) that seek recognition that biogenic CO2 emissions should not be regulated as a pollutant unde r this rule or should be exempted as de minimis. Commenters suggested that instead, bioenergy, wood products and forest

- based offsets should be clearly provided for as an opportunity for utilities and states to meet their obligations under the final rule.

Comment 8: Distributed generation/solar PV.

Response 8: Distributed RE generation may be an eligible measure as long as it meets the EM& V and other requirements for state plans under the emission standards approach. Distributed solar is considered a ren ewable energy resource and may be included in state plans as a non

- BSER RE

measure

. The EPA addresses considerations for incorporating CO 2 emission reduction measures in state plans in section VIII.K of the preamble to the final rule. The commenters will find the EPA has clarified which actions count and when such actions count generally in section VIII.K and more specifically in section VIII.K on EM&V criteria for RE and demand

- side EE resources used to adjust a CO 2 rate.
The following are summaries of th e specific public comments under this comment:

Commenters said that many states are experiencing increased implementation of Distributed Generation (DG) resources, particularly adoption of roof top solar installations in residential markets. Commenters sai d that DG represents an important component in any emission reduction plan and MidAmerican currently employs utility sponsored programs which support its continued growth. Commenters stated that the EPA should explicitly recognize DG and other327 emerging tec hnologies as eligible resources for demonstrating compliance with state compliance plans and targets.

Commenters described the benefits of distributed generation as including energy cost savings, savings in transmission and distribution losses and congesti on costs, deferred generation capacity, deferred transmission and distribution capacity, system reliability, power quality benefits, and reliability/resilience. Commenters cited a study from Arizona which found that solar PV usage saved a public utility 8 cents per kWh. Commenters stated that a net metered PV system or one that feeds back into the grid beyond what the customer needs could provide a higher value of electricity. Commenters noted that California funds a program such as this, and PV electricity value increased by 30% to 50%; commenters noted that electricity generated close to its point of use results in less line loss during transmission. Commenters noted that line loss can be as much as 20% during peak load hours. Commenters cited multiple oth er examples of solar PV usage resulting in energy efficiency and monetary savings.

Comment 9: Geothermal.

Response 9: Geothermal power may be an eligible measure as long as it meets the EM& V and other requirements for state plans under the emission standards approach. Geothermal energy is considered a renewable energy resource and may be included in state plans as a non

- BSER RE measure. WER, and in particular, waste heat to power (WHP), i.e., waste energy recovered to generate power, and industrial C HP and how they may be used in state plans is discussed in more detail in the preamble. See section VIII.I and VIII.K. The EPA has not made a decision on whether/when it will reevaluate these final emission guidelines.

The EPA addresses considerations for incorporating CO 2 emission reduction measures in state plans in section VIII.G of the preamble to the final rule. The commenters will find the EPA has clarified which actions count and when such actions count generally in section VIII.K and more specifical ly in section VIII.K on EM&V criteria for measures used to adjust a CO 2 rate.
The following are summaries of the specific public comments under this comment:

Commenters stated that properly installed geothermal heat pump (GHP) systems, including both
groun d

- source and groundwater heat pump systems, can reduce energy usage, provide useful renewable energy, and help achieve the proposal's goals when used in appropriate situations. Commenters believed that GHP systems enable Waste Energy Recovery (WER) i.e. en ergy that is normally "thrown away" via an evaporative device that consumes large quantities of water and significantly increases the PM 2.5 emissions from buildings, power plants, and industrial processes. While the proposal generally provides a broad, fl exible framework within which states and utilities can operate, commenters said that the proposal fails to address WER outside of CHP. Commenters asked that the final rule specifically include WER as a viable and legitimate tool to reduce generation needs, reduce water consumption, and PM 2.5 emissions. Commenters added that GHPs can be effectively integrated into institutional CHP systems, and states should be able to consider industrial CHP approaches in their state programs.328 Commenters said that the renewable energy assumptions in Building Block 3 (both the proposed RPS

- based structure and the alternative technical and economic approach) are overly conservative. When setting the emissions reduction requirements, commenters sai d that the EPA should take into account the availability of interstate opportunities from renewable energy and use the latest assumptions on the costs and resource potential for deploying all renewable energy sources. As a result, commenters believed that the EPA should propose in the final rule emissions reductions that go further than what is in the draft Clean Power Plan, particularly in light of the lengthy compliance period. Commenters stated that the EPA should revisit the BSER determination periodica lly, at least 8 eight years, to determine if additional emissions reductions are achievable at an affordable cost, as is already done under Section section 111(b) (1)(B) for new power plants. Commenters stated that the Geothermal Energy Association is avail able as a resource to the EPA and the various states, if they have questions about how to incorporate geothermal energy into the Clean Power Plan and resulting state compliance plans.

Comment 10 : Create incentives for innovative technologies for complianc e.
Response 10: The states have flexibility and a wide range of measures available to choose from. Both widely deployed technologies and “innovative” technologies are allowed and supported by this rule as long as they reduce CO 2 emissions from affected EGU s and meet other state plan requirements

. Direct air capture, while potentially benefitting the environment and reducing atmospheric concentrations of CO 2 , does not replace generation for affected EGUs or reduce stack CO 2 emissions from the power sector. Therefore, it is not considered an allowable measure in state plans using the emission standards approach for this rule. Preamble section VIII.K.1.b

- c discuss measures, such as CO 2 emission reductions from outside of the power sector that may not be used t o adjust CO 2 emission rates.

The EPA addresses considerations for incorporating CO 2 emission reduction measures in state plans in section VIII.I

- K of the preamble to the final rule. The commenters will find the EPA has clarified which actions count and whe n such actions count generally in section VIII.K and more specifically in section VIII.K.3 on EM&V criteria for RE and demand

- side EE resources used to adjust a CO 2 rate.
The EPA understands that NET Power may have potential to generate power with very low CO 2 emissions but that the technology has not yet been demonstrated at significant size/ scale. Regardless, it uses natural gas as its fuel source, and therefore would be covered by the CAA section section 111(b) Standards of Performance for Greenhouse Gas Emissions from New Stationary Sources: Electric Utility Generating Units rule.

The following are summaries of the specific public comments under this comment:

Commenters said that the rule structure should be revised to include incentives for innovati ve technologies for compliance.329 Commenters said that it is critical that the EPA consider the role of innovative technological solutions in meeting the carbon emissions challenge and that the rule be structured to support further innovation. Commenters st ated that the proposal as currently written seems only to contemplate those technologies that are already widely deployed. Given the degree of carbon emissions reductions that will need to be achieved for climate stabilization, commenters said that the EPA 's approach should encourage the development of highly cost effective innovative carbon pollution reduction solutions that can scale up to meet this challenge. Commenters explained that Congress intended that section 111(d) promote technological innovation . Commenters stated that the proposed rule may propel marginal dispatch changes, reinforce the move toward natural gas, and create marginal energy efficiency and renewable energy gains. However, commenters did not believe that it will necessarily drive the substantial technology investments needed to make a significant long

- term difference in global emissions, particular in view of the persistence of CO 2 in the atmosphere. While the rule proposes four distinct approaches for the states to reduce emissions f rom their power generation sector and leaves much flexibility to the individual states, commenters said its major impact will likely be to reinforce the already occurring shift from coal generation to natural gas generation. Such a shift may be important i n the shorter

- term; however, commenters said that it is critical that the rule also set the stage for more extensive emissions reductions

-- that track our nation's growing international emissions reduction commitments

-- through the use of innovative tech nology such as direct air capture.

Commenters said that the EPA should provide states and affected sources with bonus compliance credits that have some multiple of per ton reduction if they are based on the deployment of innovative technologies by power pl ants. Commenters stated that there is strong precedent for this approach because it is precisely the approach that the EPA recognized would be effective and used in its efforts to encourage innovation in the automotive sector, where the agency provided add itional compliance credits for advanced technologies that reduce GHG emissions and their permeation through the fleet. There, commenters stated, the EPA provided that certain advanced technology vehicles "would count as more than one vehicle in the manufac turer's compliance calculation." Commenters added that the EPA expressly recognized that "the potential for large future emissions benefits from these technologies provides a strong reason for providing incentives at this time to promote their commercializ ation." Commenters noted that, as to the legal basis for such incentives, the EPA argued that section 202 of the Clean Air Act "provides EPA with broad discretion in setting emissions standards. This includes authority to structure the emissions standards in a way that provides an incentive to promote advances in emissions control technology." Commenters stated that the EPA should make similar use of the broad discretion it has under 111(d) to foster compliance methods from affected sources that deploy inno vative and advanced technologies to reduce carbon emissions.

Commenters stated that working in partnership with Global Thermostat, Corning has developed a ceramic monolith that is incorporated into DAC technology and that removes CO 2 from ambient air. Com menters stated that DAC technology may be powered by waste heat from a wide range of industrial or manufacturing processes, and thus it may be placed anywhere on or near the power grid to supplement existing GHG emissions control technologies and other GHG reduction strategies. Commenters stated DAC technology has the potential to provide states and regulated sources an extremely flexible means for reducing GHGs in the atmosphere, and it should complement the source

- based emissions reduction, renewable ener gy, and demand

- side strategies being proposed by the Agency as part of a "building block" approach to reducing the330 environmental and public health risks posed by global climate change. Commenters urged the EPA not overlook the critical contribution that DA C technologies can provide to the Agency's overarching effort to reduce the concentration of GHG emissions in the global atmosphere wherever

- and whenever

- they may occur. In particular, commenters stated that the EPA should: (1) continue to address the unique characteristics of GHG pollution through the Clean Air Act and other authorities and devote attention to the need to capture existing GHG emissions in the atmosphere through DAC and other technologies; (2) suggest strategies that would allow EPA to broaden its climate change efforts under the Clean Air Act and allow use of DAC and other innovative technologies to capture GHGs; and (3) ensure that states are given maximum flexibility to structure SIPs to include cap

- and

- trade and offset programs that could incorporate
out

- of

- sector and "beyond the fence line" GHG capture strategies and technologies, including DAC technologies.

Commenters stated that case law in relation to 42 U.S.C. 7111 suggests that, in implementing the CAA, the EPA should take into consideration new and emerging technologies, and CAA implementation should help to promote the development and deployment of such technologies. As the developer of an emerging technology, The y have the potential to provide massive clean air benefits to th e United States without requiring increased cost over current emitting technologies, and supported the EPA's consideration of new and emerging technologies. Commenters concluded that, if structured properly, the CPP can help to stimulate the deployment of new, cleaner technologies into the market that, without the CPP, might have had much slower adoption, and, once deployed, will play an important role in decreasing the long

- term trajectory of carbon emissions in the United States without increasing costs to power generators and/or

consumers.

Comment 11: Innovative technology: benefits of air emission recycling.

Response 11: The EPA addresses considerations for incorporating CO 2 emission reduction measures in state plans in section VIII.I of the preamble t o the final rule. The commenters will find the EPA has clarified which actions count and when such actions count generally in section VIII.I For CO 2 emission reductions that take place at affected EGUs, refer to preamble section VIII.I for more information

. The following are summaries of the specific public comments under this comment:

Commenters stated that improved fuel burner technology still leaves a residual 20% CO 2 emissions for reclamation and that strategic air emission recycling (AER) would capture , sort, refine and distribute this 20% as CO 2 derivatives to meet the needs of current and future markets. Commenters said that reclamation enables captured CO 2 conversion into non

- recalcitrants (dry

ice for refrigeration needs, specialty CO 2 gas markets, pharmaceuticals) and recalcitrants (carbonate

- ion compounds, endless other multi

- polycarbonate end

- products.) Commenters said the limitless scope of "inside the fence" opportunities to process/synthesize residual CO 2 obviates "outside the fen ce" methods such as emissions trading and averaging. Commenters added that AER is comprised of systems that fix all CO 2 , which may be processed on demand into:331 • Composted soil

• Cellulose

- based derivatives (products that cannot be digested or hydrolyzed for ultimate release of CO 2 to the atmosphere)

• Complex C

- H

- N+ designs (biocouture)

Comment 12: Innovative technology: NET Power.

Response 12: The EPA understands that NET Power may have potential to generate power with very low CO 2 emissions but that the t echnology has not yet been demonstrated at significant size/ scale. Regardless, it uses natural gas as its fuel source, and therefore would be covered by the CAA section section 111(b) Standards of Performance for Greenhouse Gas Emissions from New Stationa ry Sources: Electric Utility Generating Units rule. As a section section 111(b) new source, any generation from a NET Power unit would not be eligible as an allowable measure to adjust existing EGU CO 2 emission rates in state plans under the emission stand ards approach. Preamble section VIII.K discuss measures, such as new NGCC units covered under section section 111(b) , that may not be used to adjust CO 2 emission rates.

The following are summaries of the specific public comments under this comment:

Comment ers said that they were developing a novel power generation system that has the potential to produce lower cost electricity from natural gas than existing systems while also virtually eliminating all air emissions, including CO 2 . Commenters stated that thi s system is based on a proprietary thermodynamic cycle, called the Allam Cycle, which utilizes oxy

combustion in combination with a supercritical CO 2 working fluid in order to drive a gas turbine. Commenters stated NET Power plants achieve a modelled net s ystem efficiency of 59% (LHV), inclusive of all parasitic loads and with full, near

- 100% carbon capture and virtually no other air emissions, which puts NET Power plants on par with state

- of

- the

- art, but full

- carbon

- emitting NGCC technology from an efficie ncy standpoint. Commenters added that the projected levelized cost of electricity (LCOE) for NET Power "Nth" power plants of 600 MWe output and near 100% carbon capture is $62.9/MWh, compared to $64.0

- 67.8/MWh for NGCC plants without carbon capture, and $8 8.6

- 134.3/MWh for NGCC with carbon capture. If CO 2 is valued at $20/ton, either through a tax or sales for enhanced oil recovery (EOR) (a conservative price in current market conditions), commenters said that NET Power's LCOE decreases to $55.5/MWh. Commen ters concluded that NET Power is not only the cleanest source of electricity from fossil fuels, but it also projects to be the lowest cost source of electricity as well. Commenters then described the potential for future deployment of the technology and no ted that the plants will not be tethered to the existing CO2 pipeline or enhanced oil recovery (EOR) field network.

Comment 13: General comments on beyond the fence

- line control opportunities.

Response 13: The final rule gives states the flexibility to include the use of a range of zero

- and low

- emitting resources for affected EGUs to achieve their CO 2 emission performance332 rate. Allowable non

- BSER measures that are tied to a state plan and achieve quantified and verified MWh savings may be used to adjust a CO 2 emission rate, provided they meet the general and specific eligibility requirements for resources used to adjust a CO 2 emission rate, described in Section VIII.K. The measures must also meet the eligibility requirements and provisions related to dem and

- side EE programs and projects, if applicable, and the requirements and criteria related to proper quantification and verification of MWhs are described in Section VIII.K

. Methane capture from coal mines or oil and gas wells, while potentially benefitt ing the environment and reducing atmospheric concentrations of CO 2 , does not meet the state plan requirements if it cannot be shown to replace generation from affected EGUs or reduce stack CO 2 emissions from affected EGUs. Therefore, it is not considered a n allowable measure in state plans using the emission standards approach for this rule. Preamble section VIII.K discusses measures, such as CO 2 emission reductions from outside of the power sector that may not be used to adjust CO 2 emission rates. CCU appl ications may be considered in state plans, if the requirements specified in the preamble are met. See section VIII.I.

The following are summaries of the specific public comments under this comment:

Commenters described several technologies that can be dep loyed immediately and that would support more economical offset of power plant emissions if control beyond the fenceline controls could be implemented. Commenters described the benefits of offsetting coal mine methane and ventilation air methane from minin g operations and noted that this technology is available and has already been installed in the US, Australia and China. Commenters added that methane from oil and gas field venting can be controlled by flaring, green completion and other emerging technolog ies. Commenters described the potential for nitrous oxide emission control that is currently being deployed in a wide range of industries (i.e., nitric acid, chemical process industries, adipic acid) in response to the UN Clean Development mechanism. Comme nters stated several technologies exist to offset this gas, which is 300 times more potent than CO2 as a GHG, and they would be employed if a market mechanisms was in place to monetize emission reductions.

Commenters added that ambient capture of CO2 for commercial use is an emerging technology that at this time is only just being scaled up to commercial scale. Commenters stated several technologies are being investigated that have potential for CCU for many applications, including algae production, EOR, a nd feedstock. Although full scale demonstration is only just being implemented, commenters said that it is one example of how new technologies can and should be encouraged to offset emissions from power generation if there was in place a mechanism to
monet ize CO2 capture.

Commenters requested that the EPA provide assurance that the emission reduction technologies described in AEE's Advanced Energy Technologies for Greenhouse Gas Reduction report will be approvable as components of state plans. Commenters s tated that the report details 40 different advanced energy technologies and services that cut carbon emissions from the electric power sector while providing other system and consumer benefits. Commenters added that states should consider these technologie s and services as they develop compliance plans. Commenters described the report as follows:333 • The solutions in the report demonstrate the breadth of options that states have at their disposal today.

• Technologies are grouped into three broad categories: b uildings and industry; electricity generation; and electricity delivery and grid management.

• Many of the technologies

- including efficiency technologies such as behavioral energy efficiency, building envelope and insulation technology, and efficient appl iances, lighting, and HVAC; and renewable generation technologies such as biomass, geothermal, hydroelectric, utility

- scale nuclear, solar, and onshore wind

- are discussed at length in the Proposed Rule and form the basis of BSER.

• Many other technologies and services

- such as industrial CHP, demand response, ESCO delivered energy efficiency, fuel cells, offshore wind, anaerobic digestion, advanced metering, energy storage, advanced transmission, smart grid data management, and voltage and reactive power optimization

- are either not mentioned or are given only cursory reference.

• The emission reduction opportunities associated with many of the technologies in AEE's report are straightforward and fall within the EPA's existing guidance for the crediting of energy efficiency and renewable energy measures.

• Other advanced energy technologies require additional consideration as to their emission reduction impacts and how those impacts may be credited in state plans.

Commenters noted that AEE has jointly submit ted comments to the EPA providing information and recommending additional steps to ensure that the Clean Power Plan adequately guides states in incorporating CHP and Waste Heat to Power (WHP) as compliance mechanisms.

Comment 14 : The EPA should encourag e use of carbon offsets.

Response 14: Out

- of

- sector offsets may not be counted toward meeting a CO 2 emission performance level for affected EGUs or a state CO 2 goal, because out

- of

- sector offsets are not connected to the electrical grid and so cannot reli ably address stack CO 2 emissions from affected EGUs. See Section V.B.3 and VIII.K.1 of the final rule preamble of the CPP. However, state plans may accommodate emission budget trading programs that may include out

- of

- sector GHG offsets, which we are finali zing as an option under the state measures plan type. See Section VIII.J.2.d of the final rule preamble of the CPP.

The EPA addresses considerations for incorporating CO 2 emission reduction measures in state plans in section VIII.K of the preamble to the f inal rule. The commenters will find the EPA has clarified which actions count and when such actions count generally in section VIII.K.

The following are summaries of the specific public comments under this comment:334 Commenters encouraged the EPA to use carb on

- offset markets to achieve CO2 emission reductions.

Commenters said that carbon

- offset markets are an efficient and advantageous means to reduce carbon pollution, fund now low

- carbon technologies and provide for habitat preservation and job creation. Co mmenters said that the proposed CPP penalizes those states and individual actors that have taken proactive measures. Specifically, commenters proposed that the EPA re

- consider the application of carbon offsets in light of: (i) the assurance granted under a mass

- based approach, (ii) the underlying similarities with demand

- side energy efficiency (EE) and renewable energy (R/E) credits, and (iii) the undeniable fact that carbon offsets are a valid BSER measure. Commenters recognized that there is a difference between carbon offsets, which occur outside the affected EGU, and demand

- side EE and R/E actions, which occur outside the affected EGU but still within the interconnected electricity system, but believed that the EPA's concern of increased emissions at the affected EGU is still present with demand

- side EE and R/E measures.

In regards to demand side EE and R/E compliance measures, commenters said that it is important to note that the proposed CPP recognizes that the accounting of such measures may require

a dditional quantification, monitoring, and verification, i.e. quantification, monitoring, and verification of R/E generation and demand

- side EE energy savings under a rate

- based approach. Commenters said that similar accounting measure could be utilized in the application of carbon offsets. Commenters argued that carbon offsets fall within the scope of BSER as they are adequately demonstrated and reasonably reliable as evidenced by offsets that have been used in Oregon since 1997 and in all three existing ca p and trade programs the Northwestern and Mid

Atlantic Regional Greenhouse Gas Initiative (RGGI), the Midwestern Accord and the Western Climate Initiative (WCI.) Commenters said that carbon offsets are reasonably efficient and noted that the in the carbon offset projects held by the Climate Trust in 2013 alone, over 1.7 million tons of greenhouse gases have been reduced with an expected reduction of 4.1 million tons of reductions to occur. Commenters added that carbon offsets are an efficient market

- based

m echanism, because regulated entities are incentivized to seek out and pursue the lowest cost reduction opportunities, with offsets being one of the cheapest.

According to the U.S. Energy Information Administration (EIA) and the EPA, commenters said that t he marginal cost of emissions reduction if a large number of offsets are available and allowed into the program would be around $20, or around $50 if no international offsets are included. Commenters concluded that carbon offsets meet the last requirement of an adequately demonstrated system, i.e., that carbon offsets can reasonably be expected to serve the interest of pollution control without becoming exorbitantly costly in an economic or environmental way. Commenters noted that the conclusion that carbon offsets are a viable BSER measure is supplemented by the fact that neither the CAA nor section 111 in particular, expressly forbid the use of emission reductions occurring at stationary sources not currently subject to a section 111 performance standard, nor has Congress expressly forbidden the consideration of offsets under section 111 by the EPA. To the contrary, commenters said, carbon offsets have already been applied under the CAA, as part of section 110 NAAQS program. Commenters said this use of carb on offsets as an emission reduction tool suggests that carbon offsets are ultimately compatible under the CAA, and illustrates that Congress is fully aware of the utility of offsets, especially when regulations threaten to impose large costs.335 Comment 15: Direct use of natural gas and/or propane should be allowed as compliance options.

Response 15: To be eligible, the emission reduction measures must be grid connected and shown to reduce CO 2 emissions from affected EGUs. The EPA addresses considerations fo r incorporating CO 2 emission reduction measures in state plans in section VIII.K of the preamble to the final rule. Commenters will find the EPA has clarified which actions count and when such actions count generally in section VIII.K.1 and more specifical ly in section VIII.K.3 on EM&V criteria for RE and demand

- side EE resources used to adjust a CO 2 rate.
The following are summaries of the specific public comments under this comment:

Commenters said that the direct use of natural gas and/or propane should be identified as a cost

effective compliance option and provide more clarity that these benefits qualify as an efficiency resource. Commenters described steps being taken in Connecticut to expand the natural gas distribution system to provide more residen ts and businesses with the opportunity to switch to a cleaner

- burning, affordable option compared to the prevailing use of fuel oil in New England. Commenters noted that propane enjoys the benefit of being available in those locations where there is no nat ural gas infrastructure.

Commenters described how direct use of natural gas and propane in homes and businesses for home heating and other thermal uses (e.g. water heating, cooking, clothes drying) can offer efficiency savings and GHG reductions compared to electric appliances. Depending on the emissions profile of the electricity generation in a state and the efficiencies of the electric and gas options being considered, commenters said that using natural gas directly to serve thermal loads can avoid the significant efficiency losses that occur when electricity is generated from higher emitting sources in a large power plant, and transmitted across power lines. Commenters said that, according to the American Gas Association, in some cases, using standard e lectric appliances for thermal needs can waste nearly 50 percent of the input natural gas energy, subsequently requiring that much more fuel to be combusted to serve the same energy needs. [2014 Playbook, American Gas Association http://www.aga.org/ourissu es/ playbook/Documents/2014AGA_Playbook_FINAL.pdf] Commenters said that the GHG benefits of propane and natural gas can be understood by engaging in "full

- fuel

- cycle" analysis.

Historically, commenters noted, most energy efficiency analyses have focused upon the efficiency of energy consumption at the site of consumption, but this "site

- based" analysis entirely ignores upstream energy consumption. When one instead engages in full

- fuel

- cycle analysis, commenters stated that more than 60 percent of the primary energy is wasted before electricity ever reaches an appliance such as a water heater. Commenters said that propane is approximately 90 percent efficient on a full

- fuel

- cycle b asis, while electricity from all sources in the United States is only slightly more than 30 percent efficient on a full

- fuel

- cycle basis. Commenters referred to a DOE/NAS study that concluded that full

- fuel

- cycle analysis gives a more accurate picture of e nergy efficiency and resource efficiency than site

- based analysis. [See http:/ /www.nap.edL1/catalog.php?record id 0 12670.] Commenters added that utilizing propane for space heating, water heating, cooking, and clothes drying, when compared to the same336 el ectric applications, results in a total GHG reduction of almost one

- half. (Although beyond the scope of EPA's current endeavor, propane also produces no mercury and far lower emissions of nitrous oxides and sulfur oxides than coal

- fired electricity generat ion.)

Commenters described the significant opportunity for increased deployment of propane technologies such as the direct use of propane in lieu of electric furnaces (particularly electric resistance) and electric water heaters. Commenters described poli cies that promote propane use such as state energy offices that encourage deployment of propane CHP with incentives such as loans, grants, tax credits, and rebates. Commenters added that state public service commissions can encourage deployment of propane Cl

- IP by removing regulatory barriers in areas such as standby rates, interconnection standards, net metering policies, and feed

- in tariffs and by giving close scrutiny to applications to build new power plants when lower carbon alternatives

- such as fuel s witching

- are available and more efficient than fossil

- fueled electricity. Commenters said that they should also prohibit electric utilities from encouraging incentives, discounts, and subsidies for all

- electric homes and businesses and using declining bloc k rates, which make electricity less expensive the more it is used. Also, commenters said, legislatures and public service commissions can encourage deployment of propane CHP with portfolio standards or energy efficiency resource standards. Commenters adde d that states can encourage the direct use of propane in residential and commercial customer classes by adopting full

- fuel

- cycle based building codes and standards.

Commenters explained that propane residential and commercial applications (like natural ga s applications) often have a first

- cost disadvantage when compared to electricity, even though on a life

- cycle basis the propane or natural gas application is more economical. Thus, commenters said that policies that assist in ameliorating this cost disadv antage are important. Regarding new construction, commenters said that there is an incentive mismatch between builder and resident because the builder, which makes the appliance decision, has the incentive to select the least expensive appliance (usually e lectric), even though for the resident the more expensive first

- cost choice

- propane or natural gas

- is most economical in the long term. Commenters added that a handful of states have rebate programs that encourage use of natural gas appliances, and if EPA does not clarify that these options are permitted (and offer the guidance required to support crediting), they may end up getting overlooked.

Commenters said that using natural gas directly in homes and businesses can have multiple benefits, including red uced overall emissions of CO2 and conventional pollutants, more affordable energy for consumers, and improved energy resilience during severe weather incidents. Commenters stated using natural gas directly in the home and business for thermal load can redu ce wasted energy and CO2 emissions by up to 75 percent, depending on the mix of generating sources on the grid for the state or region. Commenters said that when electricity is generated, the conversion of fuel into electricity results in a significant los s of useful energy inherent in the input fuel, e.g., the average coal plant loses two

- thirds of useful input energy. As electricity travels from the power plant to the customer, commenters added, the electric transmission lines lose an additional 6.5 perce nt on average through "line losses." And, on average, only 32 percent of initial energy input is delivered as useful electric power. By contrast, commenters added, from the wellhead to burner tip, natural gas is delivered with a process energy efficiency o f 92 percent, which includes energy consumed to process and move natural gas as well as losses; only 8 percent of the original energy is used or lost in producing and337 transporting natural gas to the customer. Commenters provided other references of the ene rgy efficiency benefits of natural gas in Appendix F

. Commenters said that the EPA may determine that it is constrained by Clean Air Act section 111(d) to evaluate only the reductions in emissions from affected EGUs. If so, then commenters asked the EPA to provide guidance to states that they should simply credit the reduction in affected EGU emissions resulting from natural gas direct use in the same manner as any other beyond

- the

- fence energy

- efficiency, demand site management measure, without regard to emissions from natural gas appliances that replace electric appliances. In the alternative, commenters said, if the EPA decides to credit only net emission reductions, then it would be appropriate to credit the net emission reduction from replacing electri c with natural gas thermal appliances by using a full fuel cycle analysis. Even discounting value chain and on site emissions, commenters said, multiple studies demonstrate a significant net emission reduction by switching from electric to natural gas ther mal appliances for homes and businesses. Commenters said that by calculating the net carbon emissions reduction from grid power plants that would be achieved by replacing a given number of water heaters or furnaces (e.g. in a utility rebate program) can be done using the same models of regional grid power (the mix of coal, natural gas, and renewables) as used for other outside the fence efficiency measures, along with measurement or estimates of the on

- site GHG emissions.

Commenters added that, in states w here net emission reductions can be achieved with such direct use of natural gas and propane, appliance rebate programs could also provide an option for states to reduce the cost of compliance while providing significant other benefits for their citizens, including lower energy costs and in some cases better resilience in the event of severe storms. Commenters noted that rebates for switching from electric to natural gas or propane furnaces and water heaters are currently utilized in several states.

Comme nt 16: Commenters expressed concerns about reliance on natural gas or opposed its use as a "bridging fuel."

Response 16: See preamble section V.D for an explanation of BB2 and the role of natural gas fired EGUs. Also, see preamble section XI.C for projecte d energy impacts of this final rule. CO 2 emissions from sources other than affected EGUs and other GHG emissions are outside the scope of this final rule.

The following are summaries of the specific public comments under this comment:

Commenters were conce rned that a new ozone air quality standard could constrain future natural gas development, causing both electricity and natural gas prices to increase significantly.

Commenters said that natural gas should not be considered a "bridging fuel" without consi dering climate change impacts. Commenters said that a recent study published in Nature Magazine, "Limited impact on decadal

- scale climate change from increased use of natural gas" (Oct. 15, 2014), indicates that gas from fracking will not contribute in a m eaningful way to reduction of greenhouse gases, and in some analyses, may actually unintentionally add to the carbon inventory. Commenters stated that in most markets natural gas will inhibit the needed growth in338 renewable energy choices, and gas represent s an inhibitor of a preferable and necessary energy choice to meet the EPA's stated goal of "... fewer emissions of CO2." Commenters added that, while limiting its Rule to stationary power plant sources, the EPA ignores significant other sources of added a tmospheric carbon, such as tar sands. Commenters said that these should be revisited in their own Rule making. Also, commenters said that the current rule illustrates the important difference between what's "necessary" vs. what's "sufficient." Commenters s aid that in the future methane sources will likely become more important; as could other non

- CO2 sources, such as nitrous oxides. Commenters recommended that the EPA should initiate future rules for all carbon sources, and for other greenhouse gases. Comme nters agreed that starting with power plant regulation is important, but that it needs to expand out from there to look at other carbon

intensive industries, and start to take stances and start to develop and be more energy efficient. Commenters said that we must transition as quickly as possible from all fossil fuels.

Comment 17: The EPA should allow use of all

- electric fuel cells as a compliance option.

Response 17: The EPA addresses considerations for incorporating CO 2 emission reduction measures in state plans in section VIII.K of the preamble to the final rule. The commenters will find the EPA has clarified which actions count and when such actions count generally in section VIII.K.1 and more specifically in section V III.K.3 on EM&V criteria for RE and demand

- side EE resources used to adjust a CO 2 rate. The preamble also describes the requirements for including biomass and other technologies that may be used by affected EGUs in state plans. See section VIII.I and VIII. K.

The following are summaries of the specific public comments under this comment:

Commenters added that the EPA should give recognition for all

- electric Fuel Cells which re

- use heat internally to generate electricity more efficiently and can be sited at facilities regardless of their thermal load and demand, thus avoiding T&D line losses associated with centralized generation. Commenters stated that all

- electric fuel cells can be deployed as a demand

- side resource to provide 24x7x365 power using natural g as or biogas at efficiencies nearly double that of the centralized power plants. Commenters noted that 22 states, 2 territories, and the District of Columbia have recognized the role fuel cells can play in creating a more sustainable energy infrastructure. For example, commenters added, the California Air Resources Board (CARB) in 2007 qualified fuel cells as an "ultra

- clean" technology under their existing standard and the New York Public Service Commission qualifies fuel cells under their Renewable Portfo lio Standard. Commenters said the EPA also should recognize the entire portfolio of thermal renewables: biogas and biomass pellets, solar thermal, geothermal and geothermal heat pumps, etc.

Commenters stated that it is critical that the EPA takes into acc ount the market potential of all

electric fuel cells when crafting the state emissions targets to enable state compliance plans to fully account for the abilities of clean energy technologies to play a significant role as compliance mechanisms and to reduc e emissions as much as is possible and reasonable utilizing these technologies. For example, in regards to Building Block 3 and 4, commenters said that the EPA's assessment of the market potential of distributed technologies does not include all

- electric f uel cells. Commenters stated California's Self Generation Incentive Program provides a perfect339 example of the market potential of all

- electric fuel cells when appropriate State GHG reduction programs are in place. According to the program's 2012 impact rep ort, commenters stated that all electric fuel cells contributed 288 GWh in comparison to the 639 GWh combined of all other technologies including Combined Heat and Power. Commenters added that fuel cells also resulted in the highest GHG emissions reduction s under the program, i.e., over 70,000 metric tons of CO2 emissions reductions in 2012.

Comment 18: Early retirement of coal

- fired plants.

Response 18: Any emission reductions from coal

- fired EGU retirements will contribute to progress towards meeting em ission standards in states that chose a mass

- based state goal. The overall impact will depend on what, if anything, in the state replaces the lost generation from those EGUs. See preamble section VIII.J on mass

- based state plans.

New fossil generation that meets the applicability criteria under the CAA section section 111(b) final New Source Performance Standards are not affected sources under this section 111(d) final rule for existing sources. Sources covered by the section 111(b) final rule may not be us ed to adjust affected EGU emission rates. See section VIII.K for more discussion. States may address increased generation from new sources in mass

- based plans for the purpose of discouraging emission leakage. See section VII.J for more discussion on state plan measures to address leakage concerns.

The following are summaries of the specific public comments under this comment:

Commenters described the emissions reductions available from the early retirement of coal

- fired power plants.

As a variation on effic iency improvements, commenters said that state and utility planning efforts and programs, including planned early retirements of inefficient generation resources, are another approach that can significantly drive reductions in carbon pollution. For example

, commenters stated, Colorado's Clean Air Clean Jobs Act as resulted in the public utilities commission approving plans from regulated utilities that will significantly reduce GHG emission from coal plants, largely through plant retirement. Commenters note d similar impacts in Minnesota from state actions to encourage utilities to file plans containing actions that would reduce emissions that were not already required by federal regulations and then allow the utilities to recover costs for those actions. Com menters described similar plans in Missouri to retire coal plants and recommended that the final rules include a means of capturing the emission off

- set for retirement of coal plants.

Commenters described the potential for Ultra

- supercritical plants to im prove plant efficiency and improve coal consumption as shown in China. Commenters said that a consortium of equipment manufacturers and material suppliers have been working on the development of Advanced Ultra

supercritical designs using nickel based alloy s for several years, sponsored by the U.S. Department of Energy. Commenters said that utilizing these advanced alloy materials will allow for increased steam temperatures and pressures resulting in even higher plant efficiencies over USC plant designs. Com menters said with support from industry and the U.S. DOE, the340 commercialization of Advanced Ultra

- supercritical plants would result in an almost 30% reduction in CO2 emissions per MWh over subcritical plants. Commenters concluded this magnitude of CO2 redu ction via efficiency improvement is substantial and should be part of the U.S. program to reduce CO2 emissions without the requirement for CCS. Commenters stated that the improvements in China's power generation sector will undermine US market share of hig h

- end technology like Advanced Ultra

- supercritical plants and further frustrate capital investment in new technologies bound for these markets.

Commenters stated global competition is fierce in the power generation sector and capital follows strong market signals about future infrastructure investment. Commenters said that unless the United States commits to incentivizing the replacement or retrofitting of existing old coal plants it is unlikely that any companies here will be able to sustain investments in commercialization of transformational low carbon coal technologies such as AUSC or coal chemical looping. Commenters said that undoubtedly, this will mean much of the new coal generation installed around the world will not include these technologies. Co mmenters said that replacing a sufficient amount of electricity from aging and less efficient coal plants with electricity generated by more efficient Ultra

- supercritical (USC) plants could accomplish the Administration's CO2 emission reduction goal from t he coal

- fired power generation sector without the need to add yet

- to

- be commercialized and expensive carbon capture and sequestration (CCS) technologies. Commenters said that USC plant designs are commercially available today at reasonable cost and can be provided by a number of boiler and steam turbine suppliers. Further, commenters said, these designs could be deployed in a CO2 capture ready condition to provide for future CO2 reductions after 2030. Commenters described why this is preferable to the propo sed New Source Rule that forces new coal plant to utilize unproven CCS technology and the proposed existing plant rule that pushes coal plants down in dispatch because both dictate how electricity will be generated by the power sector, i.e. natural gas and renewables. Allowing high efficiency USC coal plants to replace existing units where practicable, properly accounting for net reductions in CO2 emissions, commenters said, would leave fuel choice with states, utilities and the market. Commenters said that maintaining fuel options has been and will continue to be a risk mitigation strategy for power providers as they serve their customers and stakeholders. In addition to shielding customers from the electricity price spikes historically caused by natural ga s and renewable dominated power systems, commenters said that this approach gives states with high coal use an option to maintain jobs and contain electricity costs.

Commenters gave examples of the emissions reduction and efficiency benefits of replacing older existing sub

- critical and supercritical coal plants with Ultra

- supercritical plant designs would improve plant heat rates significantly with an equivalent reduction in CO2 emitted per MW

- hr produced. Commenters included a table comparing the heat rat e, efficiency, CO2 emission factor, and CO2 emissions reduction for four different plant designs: Subcritical, Supercritical, Ultra

- supercritical, and Advanced Ultra

- supercritical (not commercial). Commenters stated that to achieve the target reductions in CO2 emissions contemplated by the EPA's state by state targets in the proposed rule, a fair system of linking coal retirements to the construction of new USC coal units can be devised, in lieu of just ramping up more natural gas use and shutting down

more coal units. For example, commenters said, retiring 1000MW of coal units operating at 32% efficiency and 65% capacity factor and replacing that with a new 700MW coal unit with 40% efficiency and 82% capacity factor would still result in a 30% reduction in CO2 emissions.341 Commenters described the favorable results of Industrial Efficiency Programs, a DOE program that encourages facilities to become certified to Superior Energy Performance (SEP) because they have met the ISO 50001 standard and have improved th eir energy performance up to 25% over 3 years or up to 40% over 10 years.

Comment 19: Revise building codes to encourage wood construction.

Response 19: In the final rule, the EPA recognizes the value of energy efficiency as a low cost resource that can reduce CO 2 emissions from affected sources. Demand

- side EE and other non

BSER measures that are tied to a state plan and achieve quantified and verified MWh savings may be used to adjust a CO 2 emission rate, provided they meet the general and specific elig ibility requirements for resources used to adjust a CO 2 emission rate, described in Section VIII.K The measures must also meet the eligibility requirements and provisions related to demand

- side EE programs and projects, if applicable, and the requirements and criteria related to proper quantification and verification of MWhs from demand

- side EE savings are described in Section VIII.K.

The following are summaries of the specific public comments under this comment:

Commenters suggested revising building code s to encourage wood construction.

Commenters said that independent life

- cycle assessments show that wood requires less energy to produce

- and provides better insulation from cold and heat

- than steel and concrete. Commenters said that CORRIM (the Consorti um for Research on Renewable Industrial Materials is a working group of 15 research institutions that analyzed the full life cycle impacts of using wood

- based materials) found that in a typical home, wood construction offers the following advantages:

• Wood requires 17 percent less energy and generates 26 percent less greenhouse gas emissions than steel;

• Wood requires 16 percent less energy and generates 31 percent less greenhouse gas emissions than concrete.

Commenters added that another benefit of wood c onstruction is that wood products contribute to long term carbon storage because many wood products remain in use for significantly long periods of time and continue to store carbon during this time. Commenters said estimates prepared for the Food and Agri culture Organization of the United Nations state "Evidence suggests that the total sequestration of CO2 from the atmosphere associated with the products manufactured in 2007 will be 424 million tonnes CO2 equivalent."

Comment 20: Overall comments on abili ty to use electrification projects.342 Response 20: Electrification projects, while potentially benefitting the environment and reducing atmospheric concentrations of CO 2 , do not meet the state plan requirements if they cannot be shown to replace generation f rom affected EGUs or reduce stack CO 2 emissions from affected EGUs and are not grid connected. The EPA addresses considerations for incorporating CO 2 emission reduction measures in state plans in section VIII. K of the preamble to the final rule. The commen ters will find the EPA has clarified which measures may count and which measures are not eligible in section VIII.K.

The following are summaries of the specific public comments under this comment:

Commenters said that states should be able to quantify and use credits for electrification projects that result in lower carbon emissions.

Commenters noted that electrification projects, including electric vehicles, can reduce CO2 and criteria pollutant emissions overall and provided several examples of projects that states should be allowed to develop credits for.

Comment 21: Commenters said that electric vehicles should be an available compliance option.

Response 21: Vehicle electrification, while potentially benefitting the environment and reducing atmospher ic concentrations of CO 2 , does not meet the state plan requirements if it cannot be shown to replace generation from affected EGUs or reduce stack CO 2 emissions from affected EGUs. The EPA addresses considerations for incorporating CO 2 emission reduction m easures in state plans in section VIII.K of the preamble to the final rule. Commenters will find the EPA has clarified which actions count and when such actions count generally in section VIII.K.

The following are summaries of the specific public comments under this comment:

Commenters stated U.S. DOE states that the average plug

- in electric vehicle emits much less CO2 emissions than the same size and class conventional gasoline vehicle. Commenters included "Table 6. Vehicle CO2 Emissions for a 100

- mile Tr ip", which compares the CO2 emissions of different types of sedans (e.g., conventional, hybrid, all

- electric). Commenters noted that the Fuel Economy Guide published by the EPA and DOE consistently gives a much higher greenhouse gas (GHG) rating and fuel e conomy for electric vehicles (EVs) than their gasoline counterparts and provided examples. Commenters suggested that states could use their specific comparative CO2 per mile comparison to calculate and claim CO2 credit for the increased electricity usage. Commenters described the benefits of EVs in avoiding tailpipe emissions and in most states will lead to a new reduction in carbon emissions compared to the average new vehicle meeting the Corporate Average Fuel Economy standards. Commenters added that a

re cent study sponsored by the National Academy of Sciences concluded that displacement of petroleum fuels for transportation with fuels with low

- or zero

- (net) GHG emissions is one of "the most substantial opportunities for near

- term GHG reductions."

Comme nters said that numerous studies have described the significant potential of EVs to address NAAQS attainment issues in several major metropolitan areas. Commenters also described the numerous benefits of EVs and concluded that, over the longer term, vehicl e343 electrification is necessary in order to achieve deep reductions in carbon emissions from the transportation sector. While fuel efficiency improvements and reductions in per capita vehicle miles travelled can lead to some reductions, commenters stated th at achieving the goal of an 80% or greater reduction in carbon emissions by 2050 will require that a significant portion of the transportation fleet be electric vehicles powered by no carbon or very low carbon electricity. Commenters said that, given these emissions reductions, the existence of state policies supporting EVs, the inclusion of ZEV mandates in state clean air plans, the fact that the EPA has adopted regulations to incentivize electric vehicles, and fact that the federal government has adopted other policy support including tax credits for the purchase of EVs, it would be very unfortunate if the Clean Power Plan worked at cross purposes, discouraging states and utilities from acting to increase the adoption of EVs.

Commenters proposed that the rule should provide that state compliance plans that include commitments from the resident utilities to replace their diesel

- powered bucket trucks with hybrid or plug

- in hybrid electric systems be given credit for the reductions in emissions in an amount d etermined by using a methodology similar to that employed by SwRI (Southwest Research Institute) in its study. Commenters stated that these are small but significant generators of emissions and electricity

-- the idling diesel trucks that are required for the repair and maintenance of the grid. Commenters concluded that replacing these diesel

- powered trucks with the economically viable alternative of plug

- in hybrid electric systems on work trucks used to repair and maintain the electric grid can significant ly reduce overall utility emissions and should appropriately prompt more favorable reviews of state compliance plans.

Comment 22: Commenters described implementation issues associated with electric vehicle emission goals.

Response 22: Vehicle electrification, while potentially benefitting the environment and reducing atmospheric concentrations of CO 2 , does not meet the state plan requirements under a rate

- based emission standards approach if it cannot be shown to replace generation from affecte d EGUs or reduce stack CO 2 emissions from affected EGUs. The EPA addresses considerations for incorporating CO 2 emission reduction measures in state plans in section VIII.K of the preamble to the final rule. The commenters will find the EPA has clarified w hich actions count and when such actions count generally in section VIII.K.

Affected EGUs in states that choose a mass

- based emission standards approach have several options for reducing CO 2 stack emissions. Mass emission standards may not be adjusted upw ards to account for vehicle electrification, which may result in increased CO 2 stack emissions from affected EGUs.

The following are summaries of the specific public comments under this comment:

Commenters said that under the proposed CPP, states can choos e to implement rate

- based emission goals or they can convert these to mass

- based goals. In the case of a rate

- based goal, commenters said that EVs would have no direct impact on the state's ability to meet the goal because additional EVs will increase tota l electricity consumption, but will not directly impact344 the emissions rate. While there may be an indirect impact, due to the load profile of electric vehicle charging, commenters said that evidence to

- date suggests that most electric vehicle charging is l ikely to take place at home during night

- time, with a smaller share taking place at workplaces or public charging locations during the day. Commenters stated natural gas

- fired power plants, not coal

- fired power plants, are on the margin most of the time th roughout the nation, which means that increased electricity generation due to adoption of EVs will tend to increase the operation of power plants with below average CO2 emissions rates. Commenters added that adoption of EVs may facilitate increased levels of renewable electricity generation either by owners of EVs or at sites where public charging stations are located, or by utilities that see electric demand increased at night and can increase wind power generation in response.

Commenters supported the in clusion of plug

- in electric vehicles (EVs) as another potential emissions reduction measure that states can use in state compliance plans and reports, however, recommended that these credits be applied only for the growth in EVs above those reflected in th e baseline to calculate the state's average carbon emissions before CPP measures. Commenters stated that no credit should be given for EVs that would otherwise be adopted by the market but rather credit should only be given for EVs promoted as a CPP compli ance measure. Commenters concluded that it will be important that the EPA clarify what methods (and/or data sources) states can use to include EVs in their initial baseline (to establish their average emission rate) as well as in their compliance plan and report as a compliance measure.

For states that adopt a mass

- based goal, commenters said that EVs will impact them in several ways. First, commenters said, in establishing the reference case and the mass

- based goal, the state must project future electricity demand, based on existing poli cies. Commenters assumed that states would include projected future EV numbers and associated electrical consumption, based on current and/or new policies, into these projections. Commenters said that the state would then develop a state plan showing how t hey can meet or exceed the mass

- based goal. Commenters stated any new policies to support additional EV market penetration would increase total electricity demand, and associated power plant emissions, making it harder to meet the

mass

- based goal. Thus, co mmenters said, states will be discouraged from adopting additional policies to expand the use of EVs, and in fact would be incentivized to roll

- back existing policies. Commenters concluded that given the net carbon emission benefits from adoption of EVs, i t would be appropriate for the EPA to structure the 111(d) rules in a manner that encourages states and utilities to adopt policies that support EVs. Commenters said that for states that adopt a mass

- based goal, the increased electrical load due to additio nal deployment of EVs will make it more difficult for the states to achieve their goals, because it is conceivable that EVs could account for 1% of electricity demand by 2020, and up to 5

- 7% of electricity used in the leading EV states by 2030. Over the lo nger term, commenters stated, if all light duty vehicles in a state were converted to EVs, electricity consumption would rise by approximately 20%. Commenters said that these are large enough increases in electricity consumption to have a material impact o n a state's ability to meet mass

- based targets under the Clean Power Plan.

Commenters described "illustrative" approaches presented by the EPA in a November 6 supplemental guidance on translation of rate

- based to mass

- based goals. Commenters noted that
st ates may have the flexibility to use other methodologies to set mass

- based targets. Commenters suggested that one option would be for a state to make its own projection of future electricity demand, based on existing policies, but concluded that it would s till show and increase in total345 electricity demand and associated power plant emissions, making it harder to meet the mass

based goals. Thus, commenters concluded, states will be discouraged from adopting additional policies to expand the use of EVs, and o nce again would be incentivized to roll back existing policies. Commenters believed that the Proposed Rule should be modified to be "EV neutral" in a state that adopts a mass

- based goal by allowing states to adjust their mass

- based goals to reflect actual electric vehicle load as follows: Mt = M + (Eactual) x Ravg where Mt is the adjusted

mass

- based emission goal M is the unadjusted mass

- based goal adopted by a state pursuant to the final EPA Rule, Eactual is the incremental actual transportation sector ele ctrification load, subtracting out transportation load incorporated into M, Ravg is the state's average target CO2 emissions rate (either the interim or final rate). Commenters stated that this approach does not exclude transportation electrification load from the compliance demonstration, but it simply allows a state's mass

- based goals to be adjusted based upon the actual electricity consumption of EVs, consistent with the underlying goal of meeting the rate

- based targets set for the state. Commenters then described in detail how this approach might be implemented.

Commenters said that the EPA should allow states to incorporate an adjustment to mass

- based targets that would provide "headroom" for increased electricity demand associated with EV and PHEV cha rging needs. Commenters stated that the adjustment would be based on formal federal or state policy goals (including those arising out of multistate agreements) that establish state targets and reporting for the deployment of EVs and PHEVs. Commenters said in its compliance plan, a state would be required to demonstrate how it calculated the electricity demand and emissions headroom needed to accommodate clean vehicle policy commitments. Commenters added that the final Clean Power Plan should likewise clari fy that, for states that opt to use a
rate

- based standard for compliance, all generation used to power EVs and PHEVs should be treated as emissions

- free. Commenters also had concerns that increases in electricity consumption from EV and other electrificati on projects (e.g., truck

- stop electrification, port electrification, and mass transit powered by electricity, in addition to examples in the industrial sector, such as the use of an electric arc furnace in place of a coal

- fired boiler) could make CPP compl iance more difficult for states regardless of whether they choose a rate

- based or mass

based target.

Commenters noted that since a state can count avoided demand in its emission rate calculation, demand added by EVs could offset gains in efficiency. Comme nters also agreed with comments provided above regarding impacts in a mass

- based system. To avoid this, commenters suggested that the EPA let states account for carbon

- cutting load differently from more traditional load growth. Commenters stated that one p ossibility is to allow states to classify electricity emissions as not belonging in the power sector, where appropriate. For example, commenters said, if a state chooses to go through the necessary accounting it should be able to classify power plant emiss ions associated with EVs as being within the transportation sector, and therefore not subject to the CPP

-- a rule focused, by design, on power sector emissions. Commenters suggested that states be required to show that such fuel switching results in a net reduction in GHG emissions to ensure the overall carbon reduction goal of the CPP is still being met. Commenters warned of possible unintended consequences because the lines between sectors are not always clear (e.g., electricity used to power transportat ion or an industrial facility). Commenters did not want to see the Proposal altered in such a way that could result in a significant portion of electricity consumption being removed from its coverage. Commenters stated that if a state is complying through a mass

- based target, this issue could be solved by the "headroom" approach as described346 above. Commenters then gave an example of how this might play out in California with the end result that California might still be discouraged from adding EV load, even were it to use a mass

based compliance strategy that accounts for projected demand through the method proposed by EPA. However, commenters added, the difference between a state's target emission rate and the emission rate of the marginal generator (in Cal ifornia's case, 900

- 537 = 363 pounds per megawatt

- hour) may not be high enough to actually deter investments in EVs and other carbon

cutting load. Commenters encouraged the EPA work with states with ambitious EV programs to develop a solution that appropr iately balances the concerns presented. Commenters added that they did not suggest that states be authorized to count emission reductions that occur through the displacement of gasoline with electricity in their compliance plans, as this would essentially mean counting transportation emission reductions in a power sector rule. Commenters suggested that any electricity load that cuts emissions on a system

- wide basis be accounted for in a manner that avoids discouraging the growth of such load, or at least mi nimizes this discouragement.

Commenters also described the benefits of EVs, but were concerned that the mass

- based compliance option could discourage their use. Commenters proposed an approach that both removes the disincentive to additional EVs and elimi nates the ability to game the system by

over

- projecting EV load when setting mass

- based targets. Commenters said that the adjusted

mass

- based emissions targets would first be calculated ignoring any electricity use by EVs, but the targets would then be adj usted after the fact based on the actual number of EVs operating in the state in any year. Under this proposal, commenters said that the actual value of the target would not be known a priori. Commenters explained that the final target would be calculated ex post facto when the actual number of operating EVs is known and their electricity use is estimated. If states elect the mass

- based approach and want to take advantage of this adjustment, commenters said that they would need to maintain data on the numbe r and type of EVs operating in the state. Commenters did not propose any adjustment for EVs in states that choose the emissions rate approach as it is unclear if states and utilities will be penalized or will benefit by the adoption of EVs, under the rate

- based approach. Commenters stated this effect depends on whether the electricity generated to serve the vehicles comes from power plants with below average or above average emissions rates. In many states, commenters said that incremental electricity load will be served by natural gas

- fired power plants. Commenters added that another potential approach to crediting electrification projects would be similar to that used by the Voluntary Airport Low Emission (VALE) program offered by the Federal Aviation Admi nistration. In this program, commenters stated, estimates of emission reductions from projects proposed by airports applying for funding are calculated using specific methodologies published by the FAA and are submitted to the responsible air quality agenc y. Commenters also described the benefits and barriers to additional electrification of ports. Commenters said that in order for transportation electrification to be considered as a non

- BSER compliance option, however, states will have to devise an accepta ble methodology for quantifying the net emission reduction benefits of electrification, taking into account the emission reductions expected to occur in the transportation sector (from displacement of diesel fuel and gasoline as fuel sources with electrici ty) and possible increases in emissions in the electric sector if fossil fuel

- fired electric generation is used to meet the additional load. Commenters added that as more zero

emitting nuclear and renewable energy is added to the electric system, the net b enefits of electrification would be expected to increase.347 Comment 23: Reduce idling emissions from diesel trucks.

Response 23: Reduced truck idling, while potentially benefitting the environment and reducing atmospheric concentrations of CO 2 , does not mee t the state plan requirements under a rate

- based emission standards approach if it cannot be shown to replace generation from affected EGUs or reduce stack CO 2 emissions from affected EGUs. The EPA addresses considerations for incorporating CO 2 emission re duction measures in state plans in section VIII.K of the preamble to the final rule. The commenters will find the EPA has clarified which actions count and when such actions count generally in section VIII.K Further, eligible measures must be grid

- connecte d, as discussed in section VIII.K of the preamble to the final rule.

The following are summaries of the specific public comments under this comment:

Commenters stated that another established CO2 benefit from electrification is shown in a DOE report title d "Energy Use and Emissions Comparison of Idling Reduction Options for Heavy

Duty Diesel Trucks." Commenters stated the study shows that that overall CO2 emissions are reduced with electrified parking spaces at truck stops (e.g., truck stop electrification ). Commenters said the report shows an approximately 80% CO2 benefit in idle reduction from the use of electrified parking spots (EPS) for heavy duty trucks as compared with 2001 or 2007 trucks (refers to FIGURE 2. Full fuel

- cycle NOx, PM10, and CO2 emissi ons for nine scenarios.) Commenters noted that they are promoting electrification projects in Georgia such as electric vehicle technology and idling reduction technologies including EPS as part of an overall strategy to reduce ozone and PM2.5 emissions, pa rticularly in the Atlanta nonattainment area. Commenters stated that a co

- benefit of these projects is that less energy is consumed and less CO2 emissions are generated by the electric power plant to supply the electricity on a per mile basis and per hour of idling basis than running an engine on gasoline or diesel and added that this emission benefit will only improve as CO2 emissions from electricity generation decreases.

Comment 24: Benefits of use of secondary materials such as coal ash.

Response 24: Use of secondary products such as fly ash, while potentially benefitting the environment and reducing atmospheric concentrations of CO 2 , does not meet the state plan requirements under a rate

- based emission standards approach if it cannot be shown to repla ce generation from affected EGUs or reduce stack CO 2 emissions from affected EGUs. The EPA addresses considerations for incorporating CO 2 emission reduction measures in state plans in section VIII.K of the preamble to the final rule. The commenters will fi nd the EPA has clarified which actions count and when such actions count generally in section VIII.K Further, eligible measures must be grid

- connected, as discussed in section VIII.K of the preamble to the final rule.

The following are summaries of the sp ecific public comments under this comment.

Commenters discussed the impacts of coal ash on quantifying emissions reductions.

Commenters said that the Proposal forfeits an opportunity to credit further carbon savings by failing to recognize the carbon savin gs that could be gained by promoting beneficial use of secondary materials, including coal ash. In measuring the reductions in emissions of greenhouse348 gas from existing power plants combusting fossil fuels, commenters said that residual coal fly ash is an important element resulting from coal combustion that must be included in calculating the actual reductions for each unit. Commenters said that fly ash can be used as a raw material to produce Portland cement where it contributes valuable mineral component s and product enhancements. By using this resource, commenters said, mining the required minerals is avoided. Commenters added that the increased durability of concrete structures and pavements that include fly ash results in longer service life and a net reduction in greenhouse gas generated for replacing such structures and pavement. Commenters added that the U.S. Green Building Council offers LEED points for use of coal ash in concrete and brick building products.

Commenters said that another impact of the use of coal fly ash can be calculated by the amount of fly ash that is used in place of Portland cement. For each ton of fly ash that is used in lieu of a ton of Portland cement, commenters said, a ton of greenhouse gas is avoided from production of th e Portland cement replaced. Commenters said that since the year 2000, over 170 million tons of greenhouse gas production has been avoided by the use of fly ash in concrete mixtures. Commenters cited other environmental benefits included reduced need for di sposing of coal combustion residuals (CCRs) in landfills and reduced use of virgin resources. Commenters said that economic benefits include job creation in the beneficial use industry, reduced costs associated with CCR disposal, increased revenue from the sale of CCRs, and savings from using CCRs in place of other more costly material. Commenters said that the states also recognize the carbon

- savings potential from coal ash use, and that such carbon savings can command a price in a carbon cap and trade mar ket. In 2013, commenters said, the Commonwealth of Massachusetts awarded carbon "offset" credits to an EGU that sold coal ash to a concrete plant for use in manufacturing. Commenters described the how the state responded to adverse comments on the offset p lan and concluded that the final rule should not prevent certain types of state credit
programs

- including programs such as the one in Massachusetts

- as constituting well

- designed, "approvable" programs states can use to facilitate their ultimately meeting their targets under the Proposal.

Biomass Comments

Commenters described alternative biomass technologies that should be considered.

Comment 25: Soil carbon sequestration.

Response 25: A discussion regarding the use of some biomass feedstocks, including waste

- to

energy, for compliance purposes can be found in VIII.I and Section VIII.K of the preamble.

A discussion regarding the current status of the development of the revised Framework and how information from the revised Framework and the related peer r eview processes could be used to inform how states and EPA assess biogenic CO 2 can be found in Section VIII.I and Section VIII.K f or more information regarding the Framework , see: http://epa.gov/climatechange/ghgemissions/biogenic

- emissions.html

The follow ing are summaries of the specific public comments under this comment:349 Commenters said that the additional carbon storage resulting from some forms of soil carbon sequestration is not addressed in the Clean Power Plan, nor in the Second Draft BAF. Commenter s said that the EPA appears to be overlooking the effects of activities that increase soil carbon sequestration, such as increased Net Primary Productivity resulting from improved soils due to biochar amendment. If the activities induced by policy increase the amount of carbon in soils commenters said, and if they increase the amount of future carbon being sequestered, this is vitally important. Commenters added it should also result in increased production of food and feed. Based on an initial reading of t he Second Draft BAF, commenters said, it is possible that the EPA authors intended something like this to be considered "positive leakage." Commenters noted that little is written about Leakage, and no guidance is given as to how leakage should be calculat ed. Commenters asked if increases in Net Primary Productivity of soils due to biochar amendment can be considered "positive leakage", or additional carbon storage, under the revised BAF and noted that additional clarification is needed.

Commenters said th at field crop agriculture has potential to remove CO2 from the atmosphere and that in Michigan, growers can receive payment for storing carbon in the soil via private sector carbon credit trading managed through the Chicago Climate Exchange. Commenters'

ca lculations show that an acre of corn absorbs in excess of 36,000 lbs. of carbon dioxide per acre during the growing season. Commenters said that much of that carbon is eventually returned to the atmosphere as the corn crop residue decomposes or the grain i s consumed as feed or burned as biofuel, but farmers can maintain a significant amount of carbon in the soil with proper management including implementing reduced or no

- till cropping systems. Commenters stated that a Michigan State University study indicat es that for every acre of corn, 0.4 to 0.6 tons per acre year of CO2 equivalent are long term sequestered. Commenters noted that in 2012, Nebraska had nearly 1 million acres of corn in production and that if you add to this the creation of ethanol as well as the other crops grown with electric power, the commenters said that they sequester a great deal of CO2.

Commenters agreed that the CPP should allow for state implementation plans to include CO2 equivalent reductions from measures such as agricultural me thane capture, no

- till farming and sustainable forestry and grazing practices to offset power plant CO2 emissions. Commenters agreed that pairing agricultural carbon offsets with a state mandatory emissions reduction program is a way to restore the state's soils, and improve food security while improving water and air quality. Commenters took a narrower view of acceptable alternative technologies based on an overall concern that there is a need to reduce the burning of fossil fuels and not merely make burnin g them more efficient. Commenters supported better land use and waste management planning by states to address the emissions "cost of sprawl" and unnecessary agricultural waste burning. Commenters also supported a reduction in waste

- to

- energy projects beca use the generation of energy from burning waste is less efficient than burning fossil fuels.

Commenters said that adversely affecting the price of electricity will lead to economic choices to reduce the amount of irrigated land, offsetting any CO2 reductio n benefits that may occur from the regulation of our existing plants. Commenters urged the EPA to allow states the flexibility to include agricultural sequestration of CO2 emissions to comply with their emission rate goals. Commenters stated agricultural s equestration programs achieve the environmental benefit targeted by the Proposed Rule, i.e., the removal of CO2 emissions from the atmosphere, provide additional environmental benefits such as less sediment deposit in water ways and water350 supplies, and pro vide an economic benefit to rural communities and our nation's farmers and ranchers. Commenters stated that the emission reductions achieved from these programs are creditable and verifiable. Commenters described an agriculture

- based carbon sequestration
p rogram developed in Oklahoma which included no

- till farming, grassland/rangeland management, riparian buffer repair along waterways, and forest management practices. Through this program, commenters said that Western Farmers helped sequester 122,879,017 lb s of CO2 between 2009 and 2013. Commenters added Table 2, which shows results from the Oklahoma Carbon Program for 2009

- 2013. Commenters said that permitting states to include agricultural carbon sequestration programs in Section 111(d) plans is consistent with the purposes of the Proposed Rule and the EPA's Framework for Assessing Biogenic Carbon Dioxide Emissions From Stationary Sources ("Assessment Framework").

Comment 26: CO 2 as chemical feedstock.

Response 26: Biodiesel from cooking oil, while potentially benefitting the environment and reducing atmospheric concentrations of CO 2 , does not meet the state plan requirements under a
rate

- based emission standards approach if it cannot be shown to replace generation from affected EGUs or reduce stack CO 2 emissions from affected EGUs. The final rule gives states the flexibility, to use zero

- and low

- emitting resources to achieve their CO 2 emission performance
rate. Renewable energy and demand

- side EE and other non

- BSER measures that are tied to a
state plan and achieve quantified and verified MWh savings may be used to adjust a CO 2 emission rate, provided they meet the general and specific eligibility requirements for resources used to adjust a CO 2 emission rate, described in Section VIII.K. Carbon captu re and use (CCU) as a state plan measure is discussed more specifically in the preamble section VIII.I.

The following are summaries of the specific public comments under this comment:

Commenters pointed to the carbon manufacturing industry as an alternative to CCS. Commenters noted that there are real investments (Google, BP, Mitsui, Siemens, Bunge, and more) and real platforms proving their technology strategies in both the electrochem ical (Liquid Light, Novomer) and biological (LanzaTech, Industrial Microbes, Proterro, Photonol, Joule Unlimited, and more) approaches. Commenters said that these approaches seek to monetize carbon dioxide as a valuable chemical feedstock, and they offer b olt

- on solutions for brownfield and greenfield construction projects, making them more realistic for coal

- fired power plants without access to nearby geological repositories for storage. Commenters said that they eliminate the need for costly pipelines and have the potential to create jobs, reduce/diversify consumption of petroleum

- based chemical feedstocks such as petroleum and natural gas, and can help the United States (and the world) wisely utilize its vast coal reserves while balancing the needs and

co ncerns of the environment.

Commenters supported bio

- diesel made of used cooking oil as a perfect way for reuse and creation of clean fuels. Commenters supported every EPA effort to reduce environmental impact from coal and risky technology such as frackin g and shale gas.351 Comment 27: Various biomass feedstocks.

Response 27: A discussion regarding the use of some biomass feedstocks, including waste

- to

energy, for compliance purposes can be found in VIII.I and Section VIII.K of the preamble.

The following are summaries of the specific public comments under this comment:

Commenters noted that there are several biopower and biomass CHP facilities in the Southeast that are currently unintentionally producing high carbon ash or char

- ash which is a form of carbo n sequestration, and should be recognized as such. Commenters stated that the American Carbon Registry (ACR) has published a draft Methodology for Biochar Projects that aims to establish offset credits for carbon sequestration in soils via charred biomass from bioenergy. Commenters added that it has also been embraced in California, where Placer County Air Pollution Control District is currently seeking public input on a variant of the ACR biochar methodology. Commenters said that some bioenergy facilities can increase or decrease the amount of charred biomass they produce. In a biomass boiler, commenters said, the system can be modulated to run in sub

- stochiometric mode, starving the fuel of oxygen, while increasing the amount of over

- fire air to completely burn the produced gases and volatile organic compounds. Commenters stated this gives the EPA a "lever" to increase carbon sequestration from bioenergy, potentially delivering carbon negative bioenergy, and possibly rendering moot the debate over carbon ne utrality.

Commenters said that a fifth category of reductions should be carbon negative technologies that are carbon dioxide renewable (CDR), or "NET", negative emissions technologies. Commenters said that use of the term "NET" latter picks up on both me thane and nitrous oxide. Commenters noted that biochar is an excellent example of a carbon negative technology.

Commenters urged the EPA to consider life cycle greenhouse gas contributions, especially considering the massive wildfire risk in Colorado, to support woody biomass projects such like one the commenters ha ve in western Colorado which helps to create renewable energy and increase forest health by taking down some of the dangerous and dead trees that are currently standing.

Commenters stated that in addition to helping states flexibly meet emissions goals, incorporating biomass

- derived feedstocks into compliance plans will have co

- benefits for carbon and climate change. Commenters stated increasing the pace of much needed forest management will dec rease the area of forest at risk from catastrophic wildfire, reducing the acreage and intensity of fires in the future, and thus reducing the amount of carbon being released from those fires into the atmosphere.

Commenters stated that strongly believe the air pollution issues related to both regional haze and CO2 emissions are largely caused by the forest fires that have burned millions of acres of forest across the western United States. Commenters stated that Sweetwater County believes that, to reduce the CO2 and regional haze levels within the western United States, the EPA should take steps to reduce forest fires by removing the millions of acres of beetle killed trees in the western region which will reduce the fuel load within the forest and limit the size and number of forest fires. Commenters also stated that with fewer forest fires, there will be lower levels of CO2 and352 regional haze, thus removing the need for unnecessary regulations and the potential need to shut down coal fire power plants.

Commen ters pointed to an innovative form of torrefaction technology, which converts wood and plant material into an energy

- dense, friable drop

- in fuel, which utilities can co

- fire with coal in unlimited amounts, without expensive equipment upgrades or the de

- rat ing of boilers. Commenters described their "black" pellet product, its potential to use in coal

- fired plants and the expanding production capabilities and markets. Commenters stated that they also have come up with innovative ways of reducing the cost of s uch fuels, while supporting EPA's RE

- Power America's Land Initiative. Commenters urged the EPA to collaborate with staff from EPRI on this technology.

Commenters presented information on how the relatively simple conversion of pulverized coal power plants from coal to pellets can lower the net carbon output of the power sector and provide long

- term security for fuel. Commenters said that this strategy results in energy that is baseload, dispatchable, low cost, creates jobs and the infrastructure is already present. Commenters stated that although pellet fuel is 2.88 times more expensive than coal, the total cost of generation with wood pellet fuel is only 1.38 times more expensive. Based on this analysis, commenters said, coal power costs $36.74 per MWhe (o r $0.037/kWhe) versus pellet fuel power costing $50.80 per MWhe (or $0.051/kWhe). Commenters said that other than hydro (which has already been almost fully exploited in the US), wood pellet fuel is by far the lowest cost low carbon baseload solution for p ower generation. Commenters then argued that the difference in cost between an older pulverized coal plant in compliance with emissions regulations and a converted pulverized coal plant using wood pellet fuel is about $9.15/MWh or not even one penny per ki lowatt

- hour ($0.009/kWh). Commenters also stated that converting from pulverized coal to wood pellet fuel will have a significant positive net job impact in the fuel supply chain. Also, commenters said, there is no shortage of sustainable, and therefore fo rever renewing, feedstock in the traditional fiber baskets of the US and Canada. And with the ongoing changes in paper demand, commenters said, more and more wood will be available to be converted into low carbon wood pellet fuel from working forests that are managed to produce new pellet feedstock forever.

Commenters described the benefits of "wood sequestration" achieved by leaving long

- lived trees standing or using them in long

- lived products. Commenters added that purpose

- grown energy crops like switchg rass or miscanthus leave behind significant carbon in the soil after harvest. However, commenters stated a less widely known example of carbon sequestration via bioenergy was noted in the Science Advisory Board's report to EPA, referred to there as "byprod ucts like biochar which sequester significant amounts of carbon."

Commenters supported the Agency's release of the Revised Framework for Assessing Biogenic CO2 Emissions from Stationary Sources and the McCabe Memorandum because, together, they support a cl ear, science

- based approach that provides regulatory certainty while deferring important policy implementation to the states. Commenters supported the EPA's determination that waste

- derived materials, biogas and forest

- derived industrial byproducts are "li kely to have minimal or no net atmospheric contributions of biogenic CO2 emissions, or even reduce such impacts, when compared with an alternate fate of disposal." Commenters requested that the EPA clarify in the final Plan that non

- forestry cellulosic mat erials

- like urban wood, wood

- derived construction and demolition debris, and railroad ties

- be specifically included in the definition of353 "waste

- derived feedstocks" since these organic materials do not cause land use changes and do not deplete carbon stocks

. Commenters said that they operate a biomass generation project that is fueled by locally

- sourced woody biomass from trees killed by the mountain pine beetle. Commenters noted that sound forest management, including removal of these dead trees and refores tation, mitigates wildfire risks and accelerates the restoration of forest carbon uptake capability. Commenters stated that removing dead wood from the forests and using it to fuel electric generating plants, such as the Eagle Valley facility, produces ele ctricity that offsets the need to generate power from other fossil fueled power plants. Although woody biomass generating plants emit carbon dioxide, commenters said, if dead trees are left to decay they will emit both carbon dioxide and methane. Commenter s asserted that states should be allowed to include sources such as woody biomass that meet their renewable energy standards and also decreases the potential of methane emissions as well as protecting and restoring the forests.

Commenters described the eco nomic and technical potential for climate mitigation through beneficial use of methane including biomass

- fueled CHP, which has been found, even by studies critical of bioenergy, to shorten the timeframe before climate benefits are realized. Commenters adde d that because biomass resources come from carbon recently captured in the landscape by growing plants, the use of certain fast growing biomass resources, or biomass that would otherwise rapidly decompose, or otherwise be burned without energy recovery, is beneficial in the near term. In contrast, commenters stated, the use of roundwood logs, pulpwood, or larger diameter trees is shown in scientific literature as being unhelpful for short

- term purposes of climate change mitigation. Commenters said these lon g

- lived forest resources take too long to re

grow and re

- capture biogenic carbon, and that the EPA should not incentivize their use in biopower applications.

Comment 28 : Commenters said that standalone biopower facilities should be included in emission re duction plans.

Response 28: A discussion regarding the use of some biomass feedstocks for compliance purposes can be found in Section VIII.I and Section VIII.K of the preamble.

The following are summaries of the specific public comments under this commen t:

Commenters described standalone biopower facilities that are too large (20 MW to 100 MW) for their massive amounts of waste heat to be used beneficially. Commenters said that these plants, also referred to as "dedicated biomass" are typically built in i solation, away from another facility that could act as "steam host" to make use of the waste heat. Standalone biopower plants are controversial commenters said, because they use only about 1/3 of the energy in the biomass for generating electricity, wastin g the 2/3 of the energy as heat being dumped into air or surface waters. Commenters agreed with the EPA's observation that standalone biopower tends to be more expensive than natural gas fired generation, at current prices. Commenters stated the most

commo n criticism of standalone biopower is its inefficiency, and a line of argument that suggests such inefficiency must mean there is no climate benefit, or even a detriment to climate354 mitigation. However, commenters stated, given the fact that in the United S tates these facilities typically consume forestry residues, mill waste, and other materials that would otherwise decompose quickly (or be open

- burned), these facilities are a valuable contributor to the fight against fossil carbon emissions.

Commenters sa w no benefit in discouraging the use of copious supplies of waste and residual biomass in the broadly forested Southeastern United States. Commenters pointed to a report, called "Biomass Supply and Carbon Accounting for Southeastern Forests," (published by BERC et al in February of 2012) that showed that rapid growth of new biopower developments in the Southeast would result in long time

- frames until re

- sequestration in the landscape, perhaps as long as 30 to 50 years. However, commenters said, this study a lso involved modeling of existing biopower plants in the region, based on their actual feedstocks (i.e., waste and residues, rather than "whole trees"). This modeling result was briefly described by the commenters in their comments and depicted in Figure 1 8. Based on this report, c ommenters asserted that the carbon reduction benefit from current biopower is many orders of magnitude larger than the possible carbon detriment from fossil energy alternatives. Commenters said that the reason for this dynamic was not just because of the use of waste and residues that would otherwise quickly return carbon to the atmosphere, but the larger reason was because of the substantial carbon storage found in conventional forest

- products (paper, lumber, etc.), the harvest of which facilitates biomass to leave the forest. Commenters said the Southeast's longer growing season and faster growing tree species also played a role. Finally, commenters saw great benefit in any standalone biopower that consumes only wastes and residue s.

Comment 29: Sustainability (forestry, agriculture, land use management).

Response 29: A discussion regarding sustainably

- derived biomass feedstocks can be found in Section VIII.I of the preamble.

The EPA is not requiring that any new renewable resources or that any specific RE generating technology be installed as part of this rule. There are many allowable measures to choose from. In addition, the siting and permitting of new renewable generating capacity is not a function of the EPA, but rathe r a responsibility of the states. The EPA cannot impose restrictions or requirements beyond its authority

. The following are summaries of the specific public comments under this comment:

Commenters noted that the EPA has expressly recognized the "importan ce of sustainable land management in achieving the carbon reduction goals of the President's Climate Action Plan," and many states, including Oklahoma, have recognized the importance of forest and other lands for climate resilience and mitigation and imple mented programs such as the one in which Western Farmers participates. Commenters said that it is imperative that the EPA allow states the flexibility to include these programs in their section 111(d) compliance plans, because failing to do so would elimin ate any incentive for states and companies to continue or expand these programs, and the significant environmental benefits that they achieve year over year would be lost.355 Commenters stated that for biomass to be considered as a "renewable" resource full c arbon accounting should be done. Foremost, commenters stated any feedstock from permanent land conversion should not qualify, as this land is no longer available to re

- sequester emitted carbon, and does not meet even the most limited definition of sustaina bility. Commenters also stated that certified sustainable forestry practices of the fuel source used in such facilities must be verifiable. Commenters stated all biogenic emissions must be clean and non

- hazardous, and not result in emission of toxic substa nces, degrade air quality, or negatively affect public health. Commenters then went on to identify ways in which companies who use biomass could be held accountable for sustainability. Commenters concluded by stating that in order to maximize the benefits of any biomass facilities they should utilize co

- generation, a feature that should be standard in any newly constructed plants.

Commenters were concerned that EPA did not take the environmental impact to migratory birds, bats, and endangered species into consideration when requiring additional RE generation, transmission, and distribution systems to be constructed in the U.S.

Commenters had multiple concerns about the Proposed Rule's effect on sustaining wildlife, their habitats, and biodiversity with the growing incorporation of renewable energy sources.

Commenters noted that it is important to minimize and avoid potential impacts on wildlife and habitat through measures such as properly siting wind turbines to avoid environmentally sensitive areas critica l for birds and other wildlife, and ensuring chosen sites and developments are monitored and managed to minimize impacts to wildlife, as states develop their implementation plans. Commenters noted that, as with wind power, the booming solar industry could impact species but in a manner that can be mitigated and promises to have far less significant impacts than fossil fuel development like coal and natural gas. Commenters also noted that distributed rooftop solar, when done correctly, creates no land distur bance, meaning that animals and birds aren't affected by their development. Commenters stated that strong state and federal involvement is needed to guide renewable energy development to ensure that it is done responsibly and in a wildlife

- friendly manner.

Commenters also noted that biofuels and biomass energy can play a meaningful role in reducing emissions, however, a challenge of using biomass lies within in securing fuel sources that truly reduce carbon, and not encouraging other harms to the environme nt, such as habitat destruction. Commenters rejected, in the context of the Clean Power Plan, the idea of allowing allowing states to include "sustainably

- derived agricultural

- and forestry

- derived feedstocks" without providing any substantive criteria for what constitutes sustainably

- derived biomass. Commenters noted that though many states may have sustainable forestry plans and programs, and though many may recognize forests' role in climate mitigation, states' definitions of sustainable forestry exhibit considerable variation, particularly with respect to biodiversity and that this variability stands in stark contrast to the nearly universal inclusion of biodiversity as a key component or indicator of forest sustainability programs and criteria developed by independent organizations, such as by the Montreal Process.

Commenters added that without guidance like indicators for biodiversity and other aspects of sustainable forestry, states will have greatly varying levels of protection for diversity, which w ill have deleterious impacts. Commenters pointed to a recent report by the University of Georgia,356 University of Florida, and Virginia Tech of biodiversity implications of woody biomass harvesting in the U.S. southeast which found that without additional pr otections in place, wildlife habitat and biodiversity in sourcing areas for several woody biomass facilities across the region could suffer significant harm. Commenters noted that the report results also indicated that in most cases, restricting sourcing c riteria to protect native forests and wetlands would not make feedstock sourcing for those facilities prohibitively expensive; in other words, bioenergy facilities can access sufficient quantities of economically

- viable feedstocks without needing to

conver t native forests to plantations or harvest in wetlands. Commenters stated that the study offered a review of existing programs and practices that could address biomass sustainability such as forest management certification programs and biomass harvesting g uidelines that explicitly include wildlife

- protective measures.

Given the complexity of biogenic emissions and the diversity of biomass feedstocks, commenters said that states and industry will want to understand minimum expectations the EPA has for demons trating a low

- carbon biopower strategy. Commenters said that the term "sustainable land management" covers an enormous variety of practices, as do the terms "sustainable forestry" and "sustainable agriculture," but these terms are not defined in the McCabe Memo. Commenters said that it would be arbitrary to approve a class of biomass fuel based on a generic claim of "sustainability," because this is an ambiguous standard, sustainability is not a measure of carbon impacts nor is the term even mentioned in th e EPA's revised framework. Commenters added that, even if fully specified to include considerations of forest growth and removals, sustainability criteria will fail to fully account for changes in carbon emissions, and cannot be justified as a proxy for ca rbon accounting. Commenters stated the fact that a regulated EGU burns only "sustainably

- derived feedstocks" says very little about the amount of biogenic CO2 emitted by the source or the net effect of those emissions on climate change. Moreover, commenter s said, a robust definition of "sustainable" does not address the fact that there are very limited amounts of truly sustainable biomass. Commenters said that the EPA proposal to judge sustainably

- derived feedstocks in parallel with further work on the fram ework runs the risk of pre

- empting the agency's technical review process by prematurely generating exemptions for broad categories of fuel types. Commenters concluded that the EPA's plan to effectively exempt from CPP scrutiny those emissions that occur wh en EGUs combust "sustainably

- derived feedstocks" could result in a net increase of CO2 emissions for decades. Commenters said that the EPA should retract the McCabe memo and propose a scientifically and legally sound methodology to measure the carbon from biomass burned at EGU as part of state compliance plans.

Regarding the EPA's decision to include in the Plan "sustainably

- derived" forest

- derived feedstocks, commenters urged the EPA to recognize that for decades, states have managed their forests using su stainable land management practices and existing state laws promote and protect healthy forests, so the Plan should recognize that the EPA does not have the expertise or resources to set or enforce sustainability standards. Commenters encouraged the EPA to clearly state that biomass power plants that use feedstocks covered by the McCabe Memorandum are exempt from regulation under the Clean Power Plan. Commenters stated that biomass power from renewable and sustainable feedstocks should be encouraged as a co mpliance tool under Section 111(d).357 Commenters stated that the sustainability of working forests must be evaluated solely by reference to forest carbon stocks, and forest biomass must be treated as a sustainable source of carbon neutral renewable energy as long as overall forest carbon stocks are stable or growing. Commenters noted that both EPA and a recent study by the U.S. Forest Service show that that forest carbon stocks are growing at more than twice the rate of removals, and that the growth to

remova l ratio is actually increasing. Furthermore, the commenters stated that the Agency should recognize all mill and forest residuals and materials produced from these forest improvement measures as sustainably

- derived forest biomass under all circumstances in the event that EPA chooses to focus on feedstocks.

Commenters said that U.S. forests are in a long term trend of sequestering more carbon from atmospheric CO2 than is theoretically released by their harvest for use in products and bioenergy production. Be cause of this, commenters said, biogenic CO2 emissions from all types of forest biomass

- derived fuels do not contribute to atmospheric carbon levels, unlike fossil fuel emissions. Commenters added that forest biomass is a sustainable source of carbon neutr al renewable energy and will remain so as long as forest carbon stocks are stable or growing. Commenters noted that in a November 19 policy guidance memo, the EPA states "we will continue to assess and closely monitor overall bioenergy demand and landscape conditions for changes that might have negative impacts on public health or the environment." Commenters encouraged the EPA's scrutiny, with US Forest Service partners, on an appropriately large national or regional landscape scale and over appropriately long time periods (at least 5 years) in order to avoid misinterpreting shorter term management activities with the broader trend in carbon stocks. Commenters said coupling this assessment with a policy acknowledging carbon neutral status for biogenic emis sions will avoid the complexities, burden, and cost disincentives of having to qualify and verify manufacturing residuals use and of defining and tracking "sustainably

- derived" forest

- based fuels. Commenters concluded that this approach will place the EPA in the position of being a driver toward incenting sustainably managed forests in the U.S. long

- term instead of the state

- by

- state arbiter of qualifying activities.

Commenters said that, based on a preliminary review, the EPA's November 19th guidance

memor andum represents a step in the right direction indicating that "waste derived feedstocks and sustainably

- derived forest feedstocks are likely to have minimal or no atmospheric contributions of biogenic CO2 emissions, or even reduce such impacts, when compa red to an alternate fate of disposal." In defining what constitutes sustainably

- derived forest feedstocks, commenters said that the EPA should defer to the responsible state forestry agency. Commenters said that carbon sinks (e.g., forests) do not fit clea rly into the four proposed building blocks; however, the Proposed Rule and Supplemental Proposed Rule do not explicitly ban the use of carbon sinks to offset CO2. Commenters said that both states and tribes should have the opportunity to employ carbon sink s or participate in carbon offset programs. Commenters added that, due to the lack of development on tribal land, tribes should have the option to utilize their forests as carbon sinks regardless of state participation.

Comment 30: Commenters expressed co ncern about EPA exempting biogenic CO2 emissions from regulation based on sustainably

- derived feedstocks.358 Response 30: A discussion of the use of biomass feedstocks and associated biogenic CO 2 assessment can be found in in Section VIII.I and Section VIII .K of the preamble.

Biomass is not considered part of the best system of emission reduction in this rule and therefore it is not included in goal

- setting or compliance evaluations. However, similar to other technologies outside of BSER, biomass may be cons idered as a part of a state’s plan to meet the emission guidelines

. For more information regarding Building Block 3, refer to Section V.E of the preamble.

A discussion regarding the use of some biomass feedstocks for compliance purposes can be found in S ection VIII.I and Section VIII.K of the preamble.

The following are summaries of the specific public comments under this comment:

Commenters stated that section 111 requires EPA to ensure that designated facilities achieve actual emission reductions. Comme nters stated that under Section 111 of the Clean Air Act, EPA must develop presumptive emissions standards based on the "degree of emission limitation achievable though the application of the best system of emission reduction...the Administrator determines has been adequately demonstrated," [42 U.S.C. [Section] 7411(a)(1)] and require states to submit plans that meet emission the performance standards [42 U.S.C. [Section] 7411(d)]. Commenters stated that consequently, EPA must require actual emissions reduc tions at the affected source under the CPP.

Commenters stated that EPA cannot lawfully exempt a designated facility's biogenic CO2 emissions from regulation under CAA section 111(d) merely because the facility combusts "sustainably

- derived feedstocks" wit hout also showing that the result is de minimis emissions. Commenters stated that EPA has not demonstrated that the use of "sustainably

- derived feedstocks" reduces GHG emissions consistent with the application of BSER. Commenters noted that the McCabe Memo "expects that states' reliance specifically on sustainably

- derived agricultural

- and forest

- derived feedstocks may also be an approvable element of their [CPP] compliance plans," and suggest that this course of action is appropriate "given the importance of sustainable land management in achieving the carbon reduction goals of the President's Climate Action Plan." Commenters stated that the use of sustainably harvested feedstocks is not in itself an effective proxy for reducing GHG emissions, or

-- in the specific case of the CPP

-- for utilizing the best system of emissions reduction at biomass

- burning EGUs. Commenters stated that the term "sustainable land management" is used to cover an enormous variety of practices, as are the terms "sustainable forestr y" and "sustainable agriculture." Commenters stated that a survey of the sustainability requirements promulgated by academic institutions and public and private agencies demonstrates that sustainability definitions and requirements are exceptionally broad and conceptual, and are rarely if ever focused on the GHG emissions that result from the use of "sustainably" grown or harvested biomass. Commenters listed a sampling of examples. Commenters stated that if an affected source were to demonstrate that the bi omass it utilizes was grown and harvested in a manner that is consistent with the above

- listed sustainability regimes, the source might reasonably claim, per the McCabe Memo, that it relies "on sustainably

- derived agricultural

- and forest

- derived feedstock s." Commenters noted that demonstration would say very little, if anything, about the amount of biogenic CO2 emitted by the source or the net effect359 of those emissions on atmospheric CO2 loading. Commenters stated that consequently, EPA cannot meet its obl igations under CAA [Section] 111(d) by requiring affected sources to show that they rely on "sustainably

- derived feedstocks."

Commenters EPA has not demonstrated that the use of "Sustainably

- Derived Feedstocks" results in de minimis levels of GHG emissions . Commenters stated that EPA's plan to treat the use of "sustainably

- derived agricultural

- and forest

- derived feedstocks" as "approvable element of [states'] compliance plans" effectively excludes the resulting emissions from the BSER requirement. Commente rs stated however, the Agency has not shown that the biogenic GHG emissions from affected sources that burn "sustainably

- derived" biomass are de minimis and may therefore be excluded from regulation.

Commenters stated that in Utility Air Regulatory Group v . EPA, the Supreme Court considered the use of de minimis thresholds in the context of the PSD program and confirmed that EPA "may establish an appropriate de minimis threshold below which BACT is not required for a source's greenhouse gas emissions." Comm enters stated that before it can avail itself of the de minimis doctrine, though, EPA has to establish a "true de minimis level" and "must justify its selection on proper grounds" [Utility Air Regulatory Group v. EPA, 134 S. Ct. 2427, 2449 (June 23, 2014)] . Commenters stated that EPA has made no such showing in the preamble to the CPP proposal, the technical support documents, the revised Framework, or the McCabe Memo. Commenters noted that absent a demonstration that biogenic emissions from affected source s that burn "sustainably

- derived" biomass are de minimis, EPA must ensure that such sources comply with the requirements of Section 111(d). Commenters stated that the criteria established by EPA in the McCabe Memo (i.e., affected sources should utilize "su stainably

- derived agricultural

- and forest

- derived feedstocks") is not a legally adequate proxy for BSER.

Commenters added that the McCabe memo contravenes the findings of the revised Framework in several ways. First, the commenters noted that the memo wo uld broadly exempt "waste

- derived feedstocks and certain forest

- derived industrial byproducts," even though Appendix D of the revised Framework makes it clear that in many circumstances, combusting these materials for energy can result in substantial and l ong

- lasting net CO2 emissions. Second, the commenters stated that the term "sustainable land management" covers an enormous variety of practices, as do the terms "sustainable forestry" and "sustainable agriculture" but the McCabe Memo does not provide any definition of these terms. Commenters asserted, most importantly, the fact that a regulated EGU burns only "sustainably

- derived feedstocks" says very little, if anything, about the amount of biogenic CO2 emitted by the source or the net effect of those emi ssions on atmospheric carbon loading. Commenters stated that EPA's plan to effectively exempt from ESPS scrutiny those emissions that occur when EGUs combust "sustainably

- derived feedstocks" could result in a net increase of CO2 emissions for decades. Cons equently, the commenters contended that the EPA cannot meet its obligations under CAA section 111(d) by requiring affected sources to show that they rely on "sustainably

- derived feedstocks." Accordingly, the commenters stated that EPA must withdraw its Nov ember 2014 memorandum, particularly the exemption of "sustainably

- derived agricultural

- and forest

- derived feedstocks."

Commenters stated that the historical standing biomass stocks in the U.S. are evidence that biomass is a sustainable and carbon neutral feedstock that adapts to new markets. Commenters stated that biomass, when properly managed, maintains supply volumes. Commenters stated that360 biomass removals in the South more than doubled between 1952 and 2006 and biomass supply (i.e. growing

- stock volu me) also increased during this time period.

Comment 31: Ethanol.

Response 31: Fuels used for transportation are not within the scope of this final rule. The final rule gives states the flexibility, to use zero

- and low

- emitting resources to achieve their CO 2 emission performance rate (or mass). Renewable energy and demand

- side EE and other non

BSER measures that are tied to a state plan and achieve quantified and verified MWh savings may be used to adjust a CO 2 emission rate, provided they meet the general and specific eligibility requirements for resources used to adjust a CO 2 emission rate, described in Section VIII.K.

The following are summaries of the specific public comments under this comment:

Commenters cautioned that expanding the use of ethanol cou ld be detrimental to the environment unless regulatory agencies ensure that the creation and distribution of ethanol does not result in a net carbon increase to the environment.

Comment 32: Support for the use of waste

- derived feedstocks and waste

- to

- ener gy.
Response 32: A discussion regarding the use of some biomass feedstocks, including waste

- to

energy, for compliance purposes can be found in VIII.I and Section VIII.K of the preamble.

The following are summaries of the specific public comments under thi s comment:

Commenters said that the final rule should include language clarifying treatment and compliance crediting of waste

- to

- energy (WTE) facilities, and they also described the benefits of WTE.

Commenters stated that the recently released Framework f or Assessing Biogenic CO2 Emissions from Stationary Sources (Framework) provides a methodology for how the EPA could clarify WTE's role under the Rule and the associated state plans. Commenters fully supported the Framework's overall approach, as it allows for the consideration of net atmospheric contributions of GHG emissions including avoided biogenic emissions (e.g. methane). Commenters also supported the EPA's intention to rely upon the approach outlined in the revised Framework, together with properly vetted and peer

- reviewed technical studies, to recognize the climate policy benefits of waste

- derived feedstocks in its review of state plans under the Rule, as outlined in the recent memo "Addressing Biogenic Carbon Dioxide Emissions from Stationary Sourc es." Commenters expected the EPA to take the lead on properly accounting for methane's climate impacts based on science. Commenters stated that to date, most assessments demonstrating the climate benefits of WTE, including those of the EPA, have relied upo n an older model of methane's potency. However, commenters said that methane is coming under increasing focus, including by climate scientists, the U.S. State Department and the Climate and Clean Air Coalition, and the President's Climate Action Plan. Comm enters stated that the IPCC's 5th Assessment Report recently updated the 100 year global warming potential (GWP) to 34361 CO2 when climate

- carbon feedbacks are included. Commenters added that the selection of the time period of GWPs is a policy call, and a sh orter time period should be considered as current climate science reveals us much closer to tipping points than previously thought. Commenters stated this short time period is relevant to the relatively short compliance period envisioned under the Rule, an d, viewed over a shorter 20

- year timeframe, methane's GWP is 84.

Commenters recommended that EPA explore how to more fully utilize the nation's waste stream as an alternative source of fuel and lower carbon energy through the use of waste

- to

- energy (WTE) facilities. Commenters stated the because WTE provides baseload power at extremely high availability rates, generation from existing facilities are a strong foundation for building flexible and sustainable 111(d) state plans. Commenters stated that this ba se load generation can complement other intermittent renewable sources such as wind or solar, given the ubiquitous nature of trash. Commenters noted that EPA has recognized that waste derived materials have climate policy benefits that can play a role in s tate 111(d) compliance plans within its 2nd Draft of the Framework for Assessing Biogenic CO2 Emissions from Stationary Sources. Commenters stated that by enacting strong policies to promote renewable energy sources in response to the Clean Power Plan, sta tes can incentivize new WTE capacity, which will help reduce the carbon intensity of the power sector, while having the co

- benefits of increasing recycling and diverting waste from landfills of waste and the associated methane generation. Commenters stated that for states that have limited opportunities for developing other renewable energy sources expansion of Waste to Energy can provide those states with the flexibility they need to meet their performance goal.

Commenters added that a full compliance meas urement for WTE provides states with greater compliance flexibility and ensures a robust mix of renewable energy technologies. Commenters added that WTE facilities provide much needed base

- load renewable energy and assist with grid reliability, supply dive rsification, and grid frequency support. Also, commenters said, WTE facilities have higher capacity factors than other renewables and even traditional fossil generation and are typically located near load centers, reducing the demand on long distance
trans mission. With a Levelized Cost of Energy (LCOE) on par with Wind and Solar and an avoided cost of carbon of $9/ton of CO2e, commenters said that WTE is a cost effective option for renewable electricity and carbon mitigation, provided its benefits are prope rly reflected in the final Rule.

Commenters said that miscounting of WTE's renewable energy generation would not only mischaracterize WTE's effect on a state's CO2 EGU emission rate, it would also have a negative ripple effect imposing a handicap on exist ing facilities' ability to secure power purchase agreements and reinforcing hurdles faced by local governments seeking to develop facilities in lieu of landfills. Additionally, commenters said, the sustainable infrastructure investments local governments h ave made will lose value in a skewed market, especially as renewable and climate programs merge. Conversely, commenters said, clarifying states' ability to include WTE's full compliance value will result in the appropriate accounting for generating electri city and an important co

- benefit of more robust landfill diversion and subsequent methane reductions. Without clarification on this issue from the EPA, commenters said that only half of Pennsylvania's renewable energy generated by WTE would count towards g reenhouse gas intensity reduction requirements and the state would have fewer "building block 3" compliance362 options available, making the state's task of complying with the overall emission limits more difficult to achieve.

With respect to WTE facilities, commenters noted that the EPA has published a study which concludes that each ton of municipal solid waste not landfilled as a result of being processed through a WTE facility prevents the equivalent release of a ton of CO2. (www.epa.gov/epawaste/nonhaz/m unicipal/wte/airem.htm#7) Commenters added that recycling a significant percentage of a ton of MSW, consisting mainly of paper with some additional organics, should generate credits using the same assumptions, i.e., that the waste would not then form metha ne in a landfill and would not generate CO2 if the methane were flared or used as fuel. Commenters said that without clarification on this issue from the EPA, the state's ability to measure WTE's full renewable energy production towards compliance is confu sing and may be at risk due to misinterpretation. Commenters stated this would mean that only half of Oregon's renewable energy generated by WTE would count towards greenhouse gas intensity reduction requirements; the state would be leaving half of its WTE compliance "on the table" and the significant investments that have been made locally in sustainable infrastructure to combat climate change would be minimized. Without this clarification, commenters said that the state would have fewer "building block 3" compliance options available, making the state's task of complying with the overall emission limits more difficult to achieve. Because of the parallel paths both the REC credits and compliance accounting will take, commenters said that the financial viabi lity of existing WTE facilities may deteriorate, risking a resulting increase in greenhouse gases, and use of new or expanded facilities in the effort to combat climate change would also be compromised.

Commenters said that the EPA should include sustaina ble WTE power plants in Building Block Three, Renewables, as a source of reliable and dispatchable low carbon electricity. Commenters stated energy recovery utilizing WTE generating facilities should receive consideration as a favorable electric generating technology under this rulemaking not only because these WTE facilities can provide base load generation, but also for WTE's potential impact on greenhouse gas mitigation. Commenters pointed to data obtained from the Energy Information Administration regar ding municipal solid waste along with similar data from the Office of Clean Energy and noted that both designate 53 percent of the energy generated by WTE facilities as originating from biomass sources while 47 percent of the energy is designated from foss il

- fuels. Therefore, commenters concluded, expanded deployment of WTE facilities could assist states in reaching their carbon emission reduction goals by increasing the percentage of renewable energy in each state's electricity generation mix. Commenters a dded that there is significant potential for growth in this sector.

Commenters provided an extensive discussion of the benefits of WTE, including the fact that it is a viable renewable resources (the trash is both sustainable and indigenous), it generates baseload electricity with high availability, it reduces greenhouse gases, it is a cost

- competitive source of renewable energy and GHG reduction and it provides green jobs and boosts local economies. Commenters cited the benefits of WTE in terms of reducti on of landfill volume, CO2 reductions and avoidance of the potential increase in atmospheric methane. Commenters added that the combustion of waste that would otherwise be landfilled means that WTE facilities decrease our nation's reliance on more carbon

- i ntensive generating technologies while simultaneously363 extending the operational life of our nation's landfills and eliminating methane release from the decay of organic waste in a landfill.

Commenters said, since the solid waste is collected from populati on centers, locating these Waste

- to

- Energy facilities adjacent to these same population centers will reduce emissions from the transportation sector by avoiding long

- distance transport of the waste to landfills. Commenters stated that one barrier to greate r deployment of both landfill gas and anaerobic digester bioenergy is the fact that end users are often not found adjacent to the source of biogas. Commenters said that this can sometimes be addressed using innovative business transactions called "directed gas," where the biogas is cleaned

- up to pipeline quality, measured pressurized and transported through a conventional natural gas pipeline, and the same quantity of gas is removed by the end use facility at another point on the gas pipeline, with payment made for the environmental attributes of this renewable, biomass

- derived "directed gas." Commenters noted that a number of renewable resources are available which require combustion ranging from annual agricultural crop residuals and byproducts to perennia l forest byproducts to dedicated waste streams with embedded BTUs. Commenters stated this carbon resource is better suited to return to the carbon cycle as CO2 rather than in the form of methane from a landfill. Commenters concluded that all of these feeds tocks have embedded energy which can be repurposed for electric generation.

Commenters encouraged the EPA to strengthen WTE as a renewable energy generating technology under the guidelines of Building Block 3 and to consider including methane avoidance emi ssion contributions in the context of this rulemaking. Commenters noted that landfills are the third largest source of anthropogenic methane in the United States, behind enteric fermentation (cattle) and natural gas systems, and the social cost of these la ndfill methane emissions are $1.8

- $14.8 billion annually. Commenters noted that researchers at the Earth Engineering Center of Columbia University found that diverting one ton of MSW from landfilling to WTE reduces GHG emissions by 0.5 to 1 ton of carbon dioxide equivalent and that their study estimates that if all of the non

- recycled Municipal Solid Waste (MSW) that is currently landfilled each year was converted to electricity, it could power 13.8 million homes per year or about 12% of homes in the U.S (See Energy Recovery Report). Commenters also cited the EPA's Emerging Waste Conversion Technologies Report, RTI's Analysis of Emerging Plastic Conversion Technologies and the University of Texas' Recycling Residue Report to conclude that many "non

- hazardo us secondary materials" and other valuable non

- recycled materials should be recognized as "fuels" and not as wastes in future regulations.

Commenters noted that Energy

- from

- Waste (EfW) can achieve GHG reductions of 70 million tons (megatons) of CO2e per y ear, with a GHG abatement cost of approximately $9 per ton CO2e (2005$), if the U.S. moves to more sustainable waste management practices modeled after the European Union. Commenters stated the abatement cost is comparable to that of on

- shore wind, and wel l below the cost of many other GHG abatement technologies including solar PV, biomass co

- firing, and coal electrical generation with carbon capture & storage (CCS) as reported in the latest McKinsey GHG abatement cost report prepared for the United States. Commenters said that the abatement cost is also below the Social Cost of Carbon (SCC) range of $12

- $129 developed by a group of 13 U.S. Government agencies, including the U.S. EPA, Department of Energy, and Department of Commerce. Commenters explained t hat the SCC is an estimate of the economic damages associated with a small increase in carbon dioxide (CO2)364 emissions, as well as the value of damages avoided for an emission reduction. Commenters concluded the implementation of mechanisms, like EfW, that reduce GHG emissions at a cost below that of the social cost of carbon, present an overall net economic benefit

. Commenters stated that the EPA should encourage states to employ strategies like WTE that achieve co

- benefits to maximize GHG reductions and o ther environmental benefits. Commenters noted that WTE facilities are the only major source of electricity generation with a net negative GHG footprint, driven chiefly by their ability to avoid all emissions of landfill methane. Commenters stated that the Climate and Clean Air Coalition states that "actions to reduce emissions of short

- lived climate pollutants will quickly lower their atmospheric concentrations, yielding a relatively rapid climate response. Commenters stated fast action to reduce short

- live d climate pollutants ("SLCPs"), especially methane and black carbon, has the potential to slow down the warming expected by 2050 by as much as 0.5 Celsius degrees." Commenters said that a failure to address SLCPs, like methane, significantly increases the risk of crossing the 2 degree Celsius temperature increase threshold widely discussed as most likely to limit severe climate change impacts.

Commenters stated that they generate electricity through the burning of municipal solid waste (MSW). Commenters fe el that the definition of renewable energy should be expanded to include the use of MSW to generate electricity, and that they should receive credit for the avoided methane emissions that would occur if the solid waste that is burned through the electric u tility were landfilled.

Commenters also described the potential of electricity from waste water treatment plants (WWTP) based on the fact that according to the DOE, there are 886 potential WWTP projects in the Southeast, amounting to more than 200 MW of po tential generation with Florida, Georgia, and North Carolina having the greatest potential for bioenergy at WWTPs. Commenters said that life

- cycle analyses of Greenhouse Gases using the Waste Reduction Model from the Office of Wastes as well as the Municip al Solid Waste Decision Support Tool developed by the Climate and Waste Program's both illustrate that Waste

- to

- Energy facilities reduce the amount of GHGs in the atmosphere when compared to landfilling. Commenters stated that for every ton of municipal so lid waste combusted at these generating plants one ton of GHG emissions is avoided. Commenters stated the drivers that facilitate this reduction in life

- cycle GHG emissions in both of these models include:

• Avoided methane emissions that currently originat e from landfills

• Electricity generation that offsets traditional fossil fuel generation

• Added material recycling opportunities and metal recovery

Commenters added that energy derived from, among others, industrial and commercial process biomass waste, m unicipal solid waste, landfill gas, anaerobic digester gas, and wastewater treatment plant gases, should also qualify.

Commenters said that the proposed 111(d) rules largely overlook climate mitigation through beneficial use of methane from landfill gas (L FG), livestock manure, and waste water treatment365 plants (anaerobic digestion or AD) because if this methane was used for electricity or CHP, it would directly deliver significant greenhouse gas reductions, and would also offset the need for electricity gen eration from high carbon sources such as coal and natural gas. Commenters stated this is especially concerning in light of the IPCC's recent upward revision of the Global Warming Potential (GWP) of methane, from a 2007 estimated GWP100 of 25 to a 2013 esti mated GWP100 of 34 times that of CO2. Commenters encouraged the EPA to issue additional guidance for incorporating methane utilization and reductions into state implementation plans for 111(d).

Commenters supported allowing credit for methane reduction fr om biomass

- based generation such as agricultural digesters, as well as generation from landfill gas and wastewater treatment systems but also recommended that the EPA support the development of a national standard for conversion of methane to CO2 reduction for consistency. Otherwise, commenters said, each state could conceivably come up with distinct methods of calculating methane reduction credits.

Commenters noted that Colorado recently expanded the definition of eligible resources to include pyrolysis o f municipal solid waste and generating electricity from coal mine methane because these technologies show great promise to reduce greenhouse gas emissions and should be eligible as BSER. Commenters gave examples of current methane fueled generating facilit ies in operation at mines which naturally vent methane in Western Colorado. Commenters stated that methane burning produces CO2 and water, but, pound for pound, methane is a much more potent greenhouse gas than CO2, so using methane as an energy producing fuel has a positive environmental impact. Commenters stated that the methane fueled projects owned by Holy Cross Energy are reviewed and accepted under the California Air Resource Board's protocol for Mine Methane Capture. Commenters stated that Holy Cross is concerned that CO2 emissions from their mine methane capture plant may be counted as a carbon emission increase even though the CO2 is a result of burning methane. Commenters stated that this process should be viewed as carbon neutral because of the en vironmental benefits of burning methane to generate electricity. Commenters stated that the CPP should include methane fueled generating facilities in the same manner as renewables.

Commenters said according to a 2004 report commissioned by the US Department of Energy, there were 387 potential LFG energy projects in a broad region of Southeastern states, amounting to 443 MW of potential renewable energy capacity. Florida, North Caroli na, and Tennessee stand out as having the greatest potential new LFG energy projects. As of 2014, commenters said, the EPA's own voluntary Landfill Methane Outreach Program counts 126 "candidate" landfills in these same states. Commenters also noted the po tential for livestock manure AD, particularly in NC, due to the large number of hog farms. Commenters said that according to the EPA's AgStar program, North Carolina has 939 candidate hog farms producing enough manure for a technical potential electricity generation of 1,121 thousand MWh per year and that bioenergy developments at these farms would address 203,000 tons of methane per year, or an estimated 13.2 billion cubic feet per year.

Commenters said that in addition to on

- site bioenergy generation at landfills, digester gas facilities, and biomass plants, California's RPS includes biomethane co

- firing at NGCC and other EGUs. Commenters stated at least eight of the EGUs included in the Proposed Rule in California are certified by the California Energy C ommission as RPS

- eligible using biomethane, and California is currently developing new regulations to allow additional sources of biomethane366 within the state to be sent through the interstate pipeline system and designated for use in power plants. Commente rs concluded the EPA should explicitly account for the emission reduction benefits of biomethane co

- firing in state compliance plans, per the final biogenic CO2 accounting framework.

Comment 33: Criticism of waste

- derived feedstocks and waste

- to

- energy.

R esponse 33: A discussion regarding the use of some biomass feedstocks, including waste

- to

energy, for compliance purposes can be found in VIII.I and Section VIII.K of the preamble.

The following are summaries of the specific public comments under this com ment:

Commenters said that it is critical that one megawatt hour of electricity produced at WTE facilities must receive full compliance value for that megawatt hour when calculating the State's reduction in carbon intensity. Commenters said this clarificat ion is necessary, because one definition of renewable electricity used in one of the key reference documents (not in the proposed rule) is inconsistent with Federal and State laws and policies. Commenters added that a clarification from the EPA would also assure states that they can consider WTE consistent with current available science and international recognition of WTE. Commenters said that every state which includes WTE in their renewable definition, similarly identifies all the electricity they
genera te as renewable. Commenters said that the section 111(d) rule should not use a definition of renewable which only recognizes part of WTE's output and is inconsistent with other Federal and state policies.

Commenters said that because WTE prevents the gene ration of methane from waste otherwise destined for landfills, the co

- benefit of reducing methane is also captured. In fact, commenters added, the U.S. EPA has concluded that every ton of waste managed at a WTE facility actually reduces overall GHG emissio ns by a ton of carbon dioxide equivalents, largely as methane. Commenters added that improper accounting of WTE's renewable energy generation, resulting from such ambiguity, would likely understate WTE's beneficial effect on a state's CO2 emission rate and create an obstacle to existing facilities' ability to sell compliance attributes; thus reinforcing hurdles faced by local governments seeking to develop WTE facilities in lieu of landfills. Commenters assumed that when the EPA calculated RE already being generated in a state, they counted all of the electricity from municipal WTE facilities as renewable, making no effort to separate or discount the electricity generated. Commenters encouraged the EPA to provide clarifying language regarding the quantificat ion of eligible electrical output from these facilities. Commenters agreed that if the EPA prepares guidance, it should provide for and quantify credits from WTE plants and from recycling programs.

Commenters noted that the waste that is incorporated into the biomass feedstock like plastic, rubber, and metal will also create pollution once incinerated.

Commenters said that there are no true environmental benefits to burning trash because encouraging waste burning will encourage waste and increase carbon di oxide emissions. Commenters stated that the EPA made compromises with the waste burning industry to only
count one

- third of the significant carbon emissions from WTE facilities and allowed the367 Integrated Waste Services Association to provide industry drive n information on the EPA website.

Commenters expressed concern over the inclusion of municipal solid waste (MSW) in the proposed rule. Commenters stated that MSW consists of biogenic and non

- biogenic components with the split being almost evenly between bi ogenic and fossil based components. Commenters stated that only allowing the biogenic portion MSW to be compared to landfilling paints a misleading picture since it is not required that the fossil fuel component be separated out prior to combustion, which the commenters stated could lead to bad and misinformed decisions at the local government and municipality level. Commenters pointed out that combustion still requires landfill for ash, so preprocessing to remove paper, plastics, metals and organics provid es little difference. Commenters stated that there are three options for MSW:

1. Direct landfill;

2. Combustion and landfilling of the ash;

3. Preprocessing via mixed waste materials recovery and landfilling of the inert residual.

Commenters stated that the latter option would provide a better comparable around the GHG significance of the fossil fuel component of MSW.

Commenters supported the comments in the letter submitted by GAIA and others that are based on a growing body of evidence suggesting that waste incine ration and biomass have long term climate consequences including a 2014 study of U.S. biomass energy emissions that found that burning biomass is worse for the climate than burning coal.

Commenters said that we need to move to Zero Waste, not to solutions that do nothing to limit waste, increase recycling, and promote responsible production of recyclable products.

Comment 34: Renewable fuel standards (RFS).

Response 34: Fuels used for transportation, the RFS and RVO are not within the scope of this final r ule. The final rule gives states the flexibility, to use zero

- and low

- emitting resources to achieve their CO 2 emission performance rate for affected EGUs

. Renewable energy and demand

side EE and other non

- BSER measures that are tied to a state plan and ac hieve quantified and verified MWh savings may be used to adjust a CO 2 emission rate, provided they meet the general and specific eligibility requirements for resources used to adjust a CO 2 emission rate, described in Section VIII.K.

The following are summaries of the specific public comments under this comment:

Commenters described how the renewable fuel standards (RFS) have the potential to substantially and permanently reduce greenhouse gas emissions from transportation fuels, save consumers money at the gas pump, and stabilize the rural economy and how they have led to substantial investment in low

- carbon fuels. Commenters cited reports showing GHG reduction368 benefits. However, commenters were concerned that in November 2013, the EPA issued its annual proposed rule setting the Renewable Volume Obligation (RVO) for 2014 that was substantially less than allowed by statute. On November 21, 2014, in light of the controversy invoked by the proposed rule, commenters added that the EPA announced that the 2014 RFS volume targets would not be released before the end of the year. Commenters stated that a more important concern is that EPA cited the "blend wall" as a reason to reduce the required applicable volumes for cellulosic, advanced, and total renewable fue ls. Commenters stated that the EPA invoked the "general waiver" in calculating the 2014 RVO, but argued that the EPA's authority to invoke the general waiver is limited to situations where "severe" harm to the economy or environment could result, or there is inadequate domestic supply of renewable fuel. Commenters stated neither of these circumstances have occurred. Commenters said the RFS is technology and infrastructure

- driving technology, and insufficient infrastructure to incorporate ethanol into fuel f or consumers, if such an insufficiency exists, does not allow the EPA to waive the RFS requirements. Rather, commenters said, the RFS forces the regulated industry to build out the infrastructure required to utilize the entire volume of renewable fuel call ed for in the annual targets. Since the proposed rule was based on such unallowable considerations, commenters said that the EPA was right to withhold the targets rather than move forward with their flawed calculations.

Commenters encouraged the EPA to ta ke this time to return the volume targets to the full levels called authorized by Congress. Commenters noted that the EPA's negligent handling of the RFS has been extremely disruptive to the rural economy. Commenters said that it is unreasonable to add fur ther hardship to rural communities by increasing the cost of electricity for rural communities, as this proposed rule would, while denying farmers' the opportunity to assist with climate change mitigation in a way that creates value for them. Commenters sa id that the EPA should encourage rural communities to address climate change by encouraging biofuels production through the RFS rather than place rural jobs and families at risk by increasing electricity rates in the countryside, as the proposed rule is li kely to do. Commenters concluded that the final rule should include some accommodation for rural power plants, based on emission reductions achieved through the RFS.

Comment 35: Criticism of the use of biomass.

Response 35: A discussion regarding the use of some biomass feedstocks for compliance purposes can be found in Section VIII.I and Section VIII.K of the preamble.

The following are summaries of the specific public comments under this comment: Several commenters expressed concern over the inclusion of biomass combustion as an acceptable alternative energy source. Commenters stated that they do not support biomass combustion for electricity production, and other commenters stated that biomass combustion should be excluded as an acceptable alternative en ergy source. Commenters stated that the burning of biomass should not be counted as a credit towards reducing carbon emissions. Commenters cited potential health hazards of biomass burning as a reason that it should not be included in the proposed rule. Co mmenters opposed production of electricity from combustion of biomass products such as wood, wood products, forest wastes, agricultural residues and construction/demolition waste,369 because burning these materials produces particulate pollution. Commenters s aid if biomass combustion is to be included in any strategy, then best available technology pollution controls must be required.

Commenters stated many studies have found that biomass energy is more carbon

- intensive than coal and that the life

- cycle emissions associated with various sources of biomass and waste fuels are much greater than those of fossil fuels. Commenters stated that one report found that per megawatt

- hour, a mass burn biomass power plant employing "best available control technology" emits more nitrogen oxides, volatile organic compounds, particulate matter and carbon monoxide than a modern coal plant of the same size. According to the EPA's own database, commenters said, burning municipal waste is the most carbon intensive form of en ergy generation, producing over twice the amount of CO2 per unit of energy than coal plants. Commenters said that pollution control exemptions for power plants using waste derived fuels and forestry and agricultural feedstocks, should not be a component of the CPP. Commenters stated that such exemptions are opposed by the scientific community as demonstrated by a June 19, 2014 letter signed by over 90 scientists stating that "only when bioenergy results in additional carbon being sequestered above and beyon d the anticipated baseline can there be a justification for concluding that such energy use results in little or no increase in carbon emissions."

Commenters concluded that pollution control exemptions for power plants using waste derived fuels and forestr y and agricultural feedstocks should not be a component of the CPP. Commenters noted that the EPA's Scientific Advisory Board finds that biomass fuels are not carbon neutral and can, in fact, be more carbon

- intensive than coal and that, in 2013, the U.S. C ourt of Appeals struck down the EPA's exemption of all new power plants that burn biomass and similar sources of biogenic carbon emissions from the same pollution control requirements that other large facilities have to follow.

Commenters explained that al l solid biomass results in more carbon pollution per MWh at the stack than fossil fuels and that the supply of low

- carbon biomass (e.g., true residuals from forestry operations or sustainably grown dedicated energy crops, such as switchgrass) is likely to be limited. Commenters supported comments in the letter submitted by GAIA and others based on a growing body of evidence that waste incineration and biomass have long term climate consequences worse than burning coal. Citing other examples, commenters conc luded that such exemptions are opposed by the scientific community as demonstrated by a June 19th, 2014 letter signed by over 90 scientists stating that "only when bioenergy results in additional carbon being sequestered above and beyond the anticipated ba seline can there be a justification for concluding that such energy use results in little or no increase in carbon emissions."

Commenters expressed concern about the impact of biomass combustion on human health. Commenters noted that biomass combustion us es feed stocks that have been proved to harm human health: examples include wood products, agricultural residues or forest wastes, and construction and demolition waste. Commenters noted that biomass combustion facilities are often located in low income co mmunities and communities of color, often those who are most vulnerable to the emissions. Commenters stated that the EPA must require state

- of

- the

- art pollution controls if biomass is combusted, and the EPA must not assume that the impacts on human health will be adequately addressed through other regulatory processes. Commenters referenced the volume of traffic delivering fuel to the biomass combustion facilities and370 removing the wastes as adding to the real

- world burden of these plants, and these burdens are not addressed in regulations concerning boilers and energy generation facilities.

Commenters expressed concern about EPA's released Revised Framework for Assessing Biogenic CO2 Emissions which has a significant impact on the 111(d) proposed rule as it relates to impacted communities. Commenters stated that this framework asserts that climate pollution from burning waste and biomass has minimum atmospheric contribution to biogenic CO2 emissions. Commenters stated that there is a growing body of evidence to dispute this assertion. Commenters stated that incineration waste disposal on public housing properties and in municipal plants contributes to hot spot toxic neighborhoods. Commenters agreed with many of their urban sustainability colleagues that there should be no exemption for power plant waste

derived fuels, and that a precautionary protocol should be adopted.

Commenters stated that the growing body of evidence that burning waste and biomass has long term climate consequences includes a 2014 study of U.S. biomass energy emissions which found that burning biomass is worse for the climate than burning coal. Commenters stated that this adds to the many studies that have found that biomass energy is more carbon intensive than coal, and that the life

- cycle emissions associated with various sources of biomass and waste fuels are much greater than those of fossil fuels. Commenters contended, according to EPA's own database, burning municipal waste is the most carbon intensive form of energy generation, produci ng over twice the amount of CO2 per unit of energy than coal plants. Commenters stated that this has been corroborated by recent studies comparing the emissions of waste (WTE) incinerators and coal plants in Maryland and New York.

Comment 36: Valuation o f biogenic carbon.

Response 36: In November 2014, the agency released a second draft of the technical report, Framework for Assessing Biogenic Carbon Dioxide for Stationary Sources . The revised Framework, and the EPA’s Science Advisory Board (SAB) peer rev iew of the 2011 Draft Framework , finds that it is not scientifically valid to assume that all biogenic feedstocks are “carbon neutral” and that the net biogenic CO 2 atmospheric contribution of different biogenic feedstocks generally depends on various fact ors related to feedstock characteristics, production, processing and combustion practices, and, in some cases, what would happen to that feedstock and the related biogenic emissions if not used for energy production.

A discussion of the use of biomass feed stocks and associated biogenic CO 2 assessment can be found in in Section VIII.I and Section VIII.K of the preamble.

For more information regarding the revised Framework , see: http://epa.gov/climatechange/ghgemissions/biogenic

- emissions.html

The following are summaries of the specific public comments under this comment:

Commenters stated that EPA's proposed process for setting state emission targets wrongly assumes that biomass power production is carbon

- neutral. Commenters also stated that EPA's carbon

- neu tral assumption contradicts the scientific consensus on the climate impact of biogenic371 emissions. Commenters stated that EPA has incorrectly accounted for emissions in the baseline assumptions due to incorrect treatment of biogenic CO2. Commenters provided numerous references and outlined their position in their comment document. Key issues raised by the commenters are as follows:

• EPA incorrectly accounted for MW generated from biomass combustion, while not accounting for any of the associated CO2 emissions . Commenters stated that this results in an incorrect baseline, and renewable energy growth factor,

• EPA's carbon

- neutrality assumption is inconsistent with the compliance

- related approach to biomass that the Agency articulated elsewhere in the proposal.

• T he proposal lacks a coherent rationale for allowing biomass to serve as a compliance measure in the section 111(d) context.

• The climate implications of harvesting forests for energy generation purposes must reflect the losses in available carbon sequestrat ion. Claims of biomass carbon neutrality make a "baseline error" by neglecting the CO2 sequestration that would occur in the absence of exploiting forests for bioenergy

• Carbon sequestration replacement and carbon debt was not adequately addressed.

• Using bi omass in place of fossil fuels for electric generation without appropriately accounting for the factors that affect biomass CO2 implications would merely transfer emissions from the electric sector to the forest sector without providing actual climate bene fits.

• The revised Biogenic Accounting Framework describes criteria that can be used to account for biogenic greenhouse gases, but it does not explain how those criteria must be analyzed in the context of the CPP, or in permitting, or any other practical ap plication. The absence of a final, scientifically

- and legally

- valid framework is also preventing stakeholders from fully assessing the role of biomass under the CPP.

Commenters stated that the EPA declaring the incineration of biomass as carbon neutral is not helpful in getting the reductions of CO2 necessary to meet current goals. Commenters believed that trees planted for the next 50 to 100 years will not absorb the same amount of carbon that will be emitted by biomass co

- fired plants over the same time period.

Commenters stated that biomass

- derived fuel combustion should be considered carbon neutral because it is one part of the continuous cycling of carbon between the atmosphere and biomass stocks via photosynthesis. Commenters stated that in contrast, the fossil fuel combustion involves a won

- way flow of carbon that increases the amount of GHGs in the atmosphere

. Commenters stated that the magnitude of the overall reduction in emissions rates could be twice the current magnitude if co

- firing biomass we re credited under a flexible system that allowed averaging across the fleet

.372 Commenters added that the EPA should determine that biomass is carbon neutral before asking states to complete compliance plans so that states can use biomass units for complianc e.
Commenters suggested that with respect to biomass and waste

- to

- energy generation, existing biomass and waste

- to

- energy generation should be credited as zero carbon emissions for the purpose of interim state goals. Commenters said that this would facilit ate compliance with the interim state goals, avoiding exacerbating the "cliff" feared by many states, acknowledging the decline in feedstock to waste

- to

- energy plants and allowing states the time needed to deploy replacement RE that would have less negativ e air quality impacts. Additionally, c ommenters said, this method avoids disruption to existing state RPS markets that could be caused by discounting or disqualifying these technologies from compliance with the CPP.

Commenters agreed that the EPA's mixed m essages on biomass fuel must be clarified and noted that, for many states to have any hope of achieving CO2 emission reductions envisioned in BB #3, the EPA must amend its definition of affected facilities to fully account for carbon neutral biomass fuel s treams in each of the three CPP rules. In addition, commenters stated, in all aspects of the three CPP rules, biomass fuels should be categorically defined as carbon neutral to facilitate the use of this renewable resource. Commenters suggested that this c ould be accomplished by designating the biomass fuel streams categorically identified as clean cellulosic biomass in the EPA's Non

- Hazardous Secondary Material rule as carbon neutral. Commenters added that the 2011 "Draft Accounting Framework for Biogenic CO2 Emissions from Stationary Sources" prepared by EPA indicates that many biogenic fuels used to power electric generating units will be considered carbon neutral. Also, commenters said, an earlier NREL study confirmed the carbon neutral/negative status o f biomass generation. For this reason, commenters believed that a categorical determination of carbon neutrality of clean cellulosic biomass fuels is justified.

Commenters noted that biomass and wood

- derived electric generation is practically the only opti on in many states for zero CO2 emission baseload generation. Commenters said that the EPA should expedite the adoption of the BAF and incorporate the findings of biogenic fuel carbon neutrality into its proposal in a consistent fashion across all its NSPS rulemakings.

Commenters said that the EPA should clarify that to the greatest extent possible that specific biomass fuels should be defined as carbon neutral to facilitate the use of this CO2

- neutral renewable resource. Commenters stated that by designatin g biomass fuel streams categorically identified as clean cellulosic biomass in EPA's Non

- Hazardous Secondary Material (NHSM) rule as CO2

- neutral, The Agency could create more regulatory certainty on this issue. Commenters said that unless the EPA makes a b lanket determination that state

- eligible biomass and biomass included in the building block 3 calculation automatically qualifies as CO2

- neutral, its building block 3 calculations are arbitrary, invalid, and need to be recalculated. Commenters concluded th at if the Agency adjusts its stance on biomass fuels away from a blanket determination, states should be able to adjust their targets accordingly. Commenters described the benefits of biogenic carbon such as urban wood residuals to reduce the carbon footpr int of energy production, and stockpiles and inventory of fuels made from this raw material could serve as a carbon sink. Commenters said that the final rule should allow or require a percentage of these biogenic materials to be blended with energy crops.373 Commenters stated that EPA should adopt consistent treatment of biomass in the three 111 rules and make a categorical determination of carbon neutrality for biomass fuels. Commenters noted that this is justified by EPA's indication in the 2011 "Draft Accou nting Framework for Biogenic CO2 Emissions from Stationary Sources" document that many biogenic fuels used to power EGUs will be considered carbon neutral, and by an earlier NREL study which confirmed the carbon neutral/negative status of biomass generatio n.
Commenters noted that biomass energy, specifically waste biomass and residues from sustainable forestry management and forest products manufacturing, provides low

- carbon, consistent, baseload energy. Commenters said that EPA's guidelines should also rec ognize the methane avoidance associated with waste

- derived feedstocks, such as biogas and landfill gas, in providing benefits beyond carbon

- neutral. Commenters noted that while the EPA recognizes that biomass

- derived fuels can play an important role in CO2 emission reduction strategies, biomass as a renewable fuel is not treated as a non

- emitting resource in the proposal's RIA and is therefore disadvantaged as a potential compliance option. Commenters speculated that this may be because the EPA is revising its biogenic emissions GHG accounting framework in response to EPA Science Advisory Board comments. However, commenters stated that this exclusion of biomass

- derived fuels as a low

- or non

- emitting CO2 resource is inconsistent with the current scientific l iterature that suggests climate beneficial U.S. biopower is possible. Commenters encouraged the EPA to apply the latest science to develop, with the states, an appropriate GHG accounting framework for biomass as a renewable resource in state compliance pla ns.
Commenters requested that the EPA categorically exclude from the methods for determining compliance with the final NSPS those CO2 emissions resulting from the combustion of biomass or, as a minimum, CO2 emissions resulting from the combustion of biomas s derived from annual crops. In the event that the EPA is unwilling to exclude such CO2 emissions categorically, commenters asked that the EPA complete the development of its Biogenic Accounting Framework before it takes final action on the Proposed Rule, establish a default Biogenic Accounting Factor (BAF) for such CO2 emissions, and incorporate the BAF into the NSPS methodology for compliance determinations.

Commenters were concerned that biomass may not be treated as a completely carbon neutral source i n state compliance plans and urged the EPA to treat biomass in a consistent manner across the scope of the proposed rule, to include both goal setting and compliance. Commenters said that the ambiguity and delayed clarification regarding approvable biomas s feedstocks makes it difficult for states to consider whether biomass energy will be an approvable compliance measure to meet their targets. Commenters stated that the final framework must include waste sources such as animal waste, agricultural waste, la ndfill gas, and digester gas. Commenters said that once the EPA completes its biogenic CO2 accounting framework, it should re

- calculate the renewable energy numbers used for each state in the goal computation process.

Commenters said that the EPA should f ully and clearly recognize the use of biomass

- derived fuel as a carbon neutral emission reduction measure and ensure that the states have maximum flexibility in utilizing biomass as a source of renewable energy to meet their targets. Commenters added that other notable regulatory bodies such as the Intergovernmental Panel on Climate Change (IPCC) treat sustainably sourced and utilized renewable biomass feedstocks, which are used to make biofuels and products, as carbon neutral in emissions in order to avoi d double374 counting of carbon emissions and loss of carbon sinks. Commenters said that a finding of carbon neutrality will provide the certainty to states and to regulated businesses. Also, commenters said, states will be able to avoid unnecessary expenditur e of resources on biomass

- based compliance options that the EPA might later find inadequate and businesses considering investments in biomass energy facilities will know whether their biomass emissions will be counted. Commenters noted that utilities will need sufficient time to develop this alternative and to retrofit an existing plant or build biomass facilities. Commenters added that the EPA should work to encourage the use of biomass and avoid unnecessarily burdening its use by seeking to impose unworka ble and onerous verification (and similar) requirements. Commenters noted that the three proposed Section 111 rules that make up the CPP send mixed messages as to how EPA will treat the CO2 emissions associated with biomass fuels. Commenters said that in t he proposed NSPS rule (79 FR 1430), the EPA defines an affected facility as one that combusts fossil fuel for more than 10% of the heat input for any three consecutive years.

Despite the carbon neutral benefits of a particular biogenic fuel, if it is co

- fi red with fossil fuel exceeding 10% of the heat input, commenters noted that all the CO2 emissions from the facility would be regulated as if firing with only fossil fuels. In the Preamble for the new unit NSPS proposed rule, commenters added that the EPA i ndicates that the Agency may amend the final applicability definition depending on the nature of the final biogenic accounting factor (BAF) protocols. Then, commenters noted that in the EPA's proposed modified and reconstructed facilities rule (79 FR 34960 ), the 10% or less fossil fuel criteria appears to have been dropped in favor of efficiency criteria. Commenters said that in the existing source performance standard rule (79 FR 34830) the EPA acknowledged that it could not establish regulations for bioge nic emissions until it has completed a Biogenic Emissions Framework, which would incorporate the BAF. Commenters said this varying treatment of biomass generation in the three rules is confusing and counterproductive and should be amended to be consistentl y applied throughout the CPP. Once an approved method for determining carbon neutrality is established for biomass fuels, commenters said that co

- firing those fuels can be used toward achieving the goal for existing electric generating units.

In addition, commenters stated, in all aspects of the three CPP rules, biomass fuels should be categorically defined as carbon neutral to facilitate the use of this carbon neutral renewable resource. Commenters suggested that this could be accomplished by designating t he biomass fuel streams categorically identified as clean cellulosic biomass in EPA's Non

- Hazardous Secondary Material (NHSM) rule as carbon neutral. Commenters said that if the EPA chooses to take into account the net atmospheric contribution of CO2 relat ed to the growth, harvest and use of biomass fuels, then the EPA must take into account the net atmospheric contribution of CO2 related to the extraction, mining, processing and transportation of fossil fuels, because the use of these fossil fuels also cau se secondary and indirect CO2 emissions. Otherwise, commenters said, the EPA's comparison of biomass and fossil fuels will be unfairly and inappropriately weighted in favor of the use of fossil fuels.

Commenters noted that the 2011 "Draft Accounting Framew ork for Biogenic CO2 Emissions from Stationary Sources" indicates that many biogenic fuels used to power electric generating units will be considered carbon neutral. Commenters said that an earlier NREL study confirmed the carbon neutral/negative status of biomass generation. For this reason, commenters believed that a categorical determination of carbon neutrality of clean cellulosic biomass fuels is justified.375 In addition, commenters said, the categorical determination of carbon neutrality for biomass

fir ed generation will help incentivize this carbon neutral green energy, which is especially important in light of the EPA's projected low natural gas prices. Commenters concluded that the EPA should implement exemptions proposed in its Framework for Assessin g Biogenic CO2 Emissions from Stationary Sources (November 2014) to encourage biomass generation and define specific biomass sources treatment as a carbon

- neutral renewable generation sources.

Commenters said that biomass CO2 emissions should not be regula ted under either the NSPS or the Clean Power Plan regardless of what portion is fired with coal or other fossil fuels. Commenters said doing so will penalize the use of biomass energy when there are many biomass fuels, including those harvested under susta inable forestry practices that are beneficial in reducing CO2 impacts fossil fuels. Commenters justified the carbon neutral status of biomass

fired generation citing the 2011 "Draft Accounting Framework for Biogenic CO2 Emissions from Stationary Sources" a nd a January 2004 NREL study (NREL/TP

- 510

- 32575). Commenters added that the exclusion for biomass

- fired generation will help incentivize this carbon

- neutral sustainable energy resource, which is especially important in light of the EPA's projected low
natu ral gas prices. Commenters stated that some areas of the country, especially the southeast, have few large scale renewable alternatives without biomass generation and that biomass generation provides for reliable base load CO2 neutral generation, which is not possible for wind and solar generation. Commenters added that biomass

- fired generation has a positive financial impact on the local community since the fuel typically comes from within 70 miles of the facility, which creates jobs in the community in su pport of recovery, transport, and preparation of the wood residues. Commenters provided an example from the Gainesville Regional Utilities to illustrate the benefits of using "waste wood."

Commenters said that the EPA should clearly require the states to t reat waste biomass as carbon

neutral, and the EPA should direct that the states treat waste biomass (whether deemed "existing" or "new") as carbon

- neutral in light of the Congressional action to date on this topic. Commenters said that assuming their Wood ville plant is carbon neutral, a 5

- year delay, and a 300 lbs/MWh increase in the target, the $2.9 billion impact drops to roughly $800 million. In addition, commenters said, waste biomass facilities like ETEC's facility that were built pursuant to incentiv es established by Congress since the Energy Policy Act of 2005 must be treated as "new" renewable energy facilities under the CPP.

Commenters justified carbon neutrality based on the EPA Endangerment Finding, 74 Fed. Reg. 66496 (Dec. 15, 2009), and annual GHG emissions inventories, that show CO2 emissions resulting directly from the combustion of biomass derived from annual herbaceous crops are inconsequential to the global warming process, (i.e., they are carbon neutral). Commenters concluded that the EPA must exclude herbaceous crop

- derived CO2 emissions from regulation under section 111 of the CAA, 42 U.S.C. Section 7411, because such emissions do not present a significant risk to human health and welfare and to include such emissions would be in excess o f EPA's authority and arbitrary and capricious.

Commenters added that the EPA's Renewable Fuel Standard Program (RFS2) and the 2006 International Panel on Climate Change (IPCC) Guidelines also support carbon neutrality. For example, commenters noted, the E PA has said that ethanol carbon can be thought of as cycling from the environment into the plant material used to make ethanol and, upon combustion of the376 ethanol, back into the environment from which it came. Commenters stated this same analysis should be applied to the use of other biomass fuels. As a result, commenters concluded, CO2 emissions from biomass

- based fuels combustion should not be included in their lifecycle emission results. Commenters stated that heat rate improvements are likely to be the only building block that might be available to independent cogeneration plants using biomass fuel because the available methods for reducing CO2 emissions at these biomass

- fired facilities are quite limited. Consequently, commenters said, the EPA should tr eat biomass

- fired facilities differently, by considering the biogenic and carbon

- neutral nature of their CO2 emissions. Among other things, commenters added, the EPA should recognize that the use of renewable biomass fuels, to the extent possible, represen ts BSER.

Commenters stated that the EPA should explicitly include biomass and biomass co

- firing as a component of the CPP because clarity is essential, given that biomass co

- firing has not been included in many federal or state renewable initiatives. Comme nters said that the EPA should include biomass in Building Block 1 or specifically identify biomass co

- firing as a compliance option for states, without incorporating into the BSER. Commenters stated integrating sustainable land use strategy is a critical step to mobilize biomass, and EPA, USDA and others should work with industry, NGOs and land management experts to develop a model "biomass sustainability framework" that states can use in the 111(d) plans. Commenters added that the EPA should level the pla ying field and place solid biomass fuel on par with other renewable energy sources as a priority by utilizing:

• Incentivization, grants, tax credits

• Research and development

• Logistical Support.

Commenters stated that generating power using biomass from tree s is highly inefficient and carbon intensive, which will most likely increase atmospheric CO2 concentrations for decades and centuries to come. Commenters stated that the assumption that biomass CO2 has no effect on the climate is scientifically indefensib le and illogical. Commenters stated that this assumption should not be used in neither the states' nor the EPA's calculations. Commenters stated that biomass from trees may be renewable under stringent circumstances, but most current industry practices are neither clean nor climate friendly.

Commenters raised concerns that the proposed rule's conflicting statements and lack of support for assertions that biomass may be carbon neutral with respect to the role of renewable energy in both target

- setting and st ate compliance efforts is disturbing and may result in Agency action that is arbitrary and capricious. Commenters stated that although the EPA released a revised draft version of its framework on November 19, 2014, along with a memorandum discussing EPA's approach to evaluating biomass CO2 emissions, the revised "framework," remains in draft form, and the memorandum appears to chart a policy course that has little to do with the framework in any event. In this context, commenters said that it is difficult i f not impossible to evaluate whether and how the EPA intends to count CO2 emissions from biomass combustion in setting state targets or evaluating state compliance plans.377 Commenters also noted that biomass fuel is not carbon neutral, its emissions can exce ed those of fossil fuels and all CO2 sources, biogenic and anthropogenic, cause global warming. Commenters stated that the assumption that biomass is carbon neutral tends to cut short systematic comparisons with fossil fuels by automatically excluding the impact of biomass CO2 emissions on global warming. Commenters said such analyses are essential to prevent unintended consequences such as investments of capital and other resources in false solutions, disruption of agricultural economies caused by overprod uction, ecological damage caused by deforestation, negative public health impacts caused by air pollution and, of course, more destructive global warming. Commenters objected to current practices in Europe and all states except Massachusetts where whole tr ee biomass is being co

- fired with coal and counted as zero carbon. Commenters said that burning wood releases more CO2 per unit of heat than coal, and because it burns at lower temperature, it produces less electricity per unit of heat than does coal. Acco rding to the IPCC Special Report, commenters said that not all forms of renewable energy are low carbon or necessarily sustainable. For example, commenters said, biomass may be overharvested faster than it can grow (with major implications for biodiversity , water and other environmental goods and services), and it releases CO2 when it burns. Commenters stated that biomass like natural gas can be characterized along a carbon intensity continuum into two categories: "high carbon biomass" and "lower carbon bio mass," but never zero carbon biomass. Commenters said that "lower carbon biomass" includes algae, rapidly growing annual plants, "forest waste," blow

- down, and thinnings from forest management, and whole tree woody biomass is always "high carbon biomass" b ecause of its high CO2 emissions and the very long time required for a replacement tree to grow.

Commenters said that biomass and fossil CO2 are indistinguishable in terms of their atmospheric forcing effects and that the EPA cannot assume that biomass CO2 emissions have no effect on the climate. Commenters stated that claims about the climate benefits of biomass energy turn entirely on "net" carbon cycle effects, particularly the possibility that new growth will resequester carbon emitted from combustion, and/or the possibility that biomass combustion might "avoid" emissions that would otherwise occur. But even if these net carbon cycle effects are taken into account, commenters said that emissions from biomass power plants can increase atmospheric CO2 conc entrations for decades to centuries depending on feedstocks, biomass harvest practices, and other factors. Commenters stated multiple studies have shown that it can take a very long time to discharge the "carbon debt" associated with bioenergy production, even where fossil fuel displacement is assumed, and even where "waste" materials like timber harvest residuals are used for fuel. Commenters stated one study, using realistic assumptions about initially increased and subsequently repeated bioenergy harvest s of woody biomass, concluded that the resulting atmospheric emissions increase may even be permanent.

Commenters presented a technical memorandum on the role of biomass energy in the EPA's greenhouse gas rule. Commenters noted that the only place where bi omass (but not waste) emissions are counted is in the EPA's going forward modeling, the model runs that the Agency conducted to determine a least

- cost pathway for states to achieve their emissions goals. There, commenters stated, emissions from standalone biomass plants are counted, along with emissions from biomass that is co

- fired at fossil fueled plants. Commenters added that the IPM modeling shows very low levels of biopower development. Commenters estimated CO2 emissions from burning wood in biomass pl ants and compared the emissions to natural gas and coal plants. Table 1 (titled: “CO2 emissions at the stack for biomass, coal, and natural gas electricity generation”)378 shows that per megawatt

- hour, CO2 stack emissions at the biomass plant are about 145% t hose of coal plant, and 250%

- 340% those of a gas plant (depending on whether it is a single cycle plant, or employs a combustion turbine.) Commenters examined arguments for carbon neutrality, such as "it would decompose anyway" and presented modeling res ults showing that after 10 years of operation, a 50 MW facility would have emitted about 6.3 million tons of CO2, whereas if those fuels had been left unburned, CO2 emissions would have been about 2.3 million tons, a difference of 4 million tons. Commenter s also refuted the argument that biomass is carbon neutral because forests take up CO2. Commenters said that numerous scientific studies demonstrate that carbon emissions of biomass power plants are not offset by new forest growth for decades, and that mea nwhile, forest carbon uptake is decreased by the very harvesting required to fuel biomass power plants. Commenters added that for biomass facilities that are harvesting new whole trees as fuel, forest modeling demonstrates that it takes 35 to more than 90 years for new forest growth to offset the extra CO2 emissions from burning biomass rather than fossil fuels, with shorter offsetting times for biomass

- coal comparisons, and longer times for biomass

- natural gas comparisons.

Commenters cited information show ing the CO2 emission impacts of burning wood compared to bituminous coal and of co

- firing of biomass with coal and the relatively low efficiency of utility

scale biomass boilers. Commenters addressed the carbon life cycle controversy and noted that a panel of the Scientific Advisory Board released an assessment in 2012 of the EPA's proposal for accounting for carbon emissions from biomass combustion within the greenhouse gas PSD permitting program and stated that the EPA is currently revising its guidance f or PSD permitting of biomass combustion. Commenters said that it would be inconsistent with the overall framework of the Clean Power Plan for the EPA to account for the life

- cycle carbon emissions of biomass

- derived fuels when it has not looked at the life

- cycle carbon impacts of other fuels, but rather only at the stack emissions from coal

- and gas

- fired units. Commenters said that if the EPA were to allow biomass to be treated as a low

- carbon emission source, this would amount to a backdoor carbon offset scheme, which the EPA has otherwise prohibited. Commenters added, if the agency were to grant biomass status as a low

- carbon resource based on life

- cycle impacts, it would then also have to factor in the life

- cycle carbon impacts of coal and gas production

. Commenters said that the EPA should only permit states to count net carbon emission reductions from new carbon

- emitting generation toward Section 111(d) compliance in order to prevent

over

- counting of emission reductions. Commenters stated that states ma y choose to build new natural gas plants, convert existing coal plants to natural gas facilities, or increase the capacity utilization of existing natural gas facilities to comply with state targets. Commenters added that the proposed rule also contemplate s the use of other carbon

- emitting sources of energy, such as biomass, for Section 111(d) compliance. Commenters explained that it is important to understand that while this new generation may displace power from higher carbon

- intensive sources, new carbon emissions will also be created. Additionally, commenters stated such new generation may even displace existing and potential zero

- carbon RE sources and reduce deployment of EE

measures.

Commenters said that biomass

- derived fuels have low energy value rel ative to fossil fuels, and transportation and processing of large quantities of the biomass can negate any carbon benefits the fuel might provide. In addition, commenters said, even where commitments are made to sustainably source biomass, such as using on ly agricultural waste products, compliance with379 these commitments must be carefully monitored to ensure that non

- sustainable fuel crop biomass is not used if the primary supply runs low. Commenters added that the time scale over which biomass resources seq uester carbon is far slower than the rate at which carbon is emitted during combustion, rendering biomass a poor strategy for reducing atmospheric carbon levels in the coming decades. Commenters concluded that the carbon benefits of biomass fuels are too

u nreliable for these fuels to be part of a state's compliance strategy. If EPA determines otherwise, commenters said that it must provide guidance about how to calculate the overall carbon emissions associated with biomass production and combustion, a task already underway at the agency. Commenters said that the EPA cannot assume, as it has stated in the proposed rule, that "broadly speaking, burning biomass

- derived fuels for energy recovery can yield climate benefits as compared to burning conventional foss il fuels." 79 Fed. Reg. 34,924. Any estimate of carbon emission reduction will be highly dependent on the source of the biomass and the conditions of its combustion, and commenters said that the EPA must establish standards for monitoring these factors whi ch states must follow if seeking to use biomass as part of the plan. The EPA recently released its Revised Framework for Assessing Biogenic CO2 Emissions from Stationary Sources, and if the EPA intends to apply this framework to the Clean Power Plan, comme nters stated that there should be an opportunity to submit additional public comments on that issue.

Commenters agreed that forest biomass should be considered carbon neutral and that the EPA should allow states to biomass

- derived fuel in affected EGUs as an emission reduction measure. Commenters said that research shows that harvest residues and material removed from forests through thinning and other stand improvement measures do not increase carbon accumulations in the atmosphere. Commenters added that t he EPA should clarify which forest

- derived industrial byproduct feedstocks are considered carbon neutral and what constitutes "sustainably derived" biomass.

Commenters said that methane from digesters and landfills is not fossil fuel and should be treated as biomass in that its combustion products are carbon neutral. Commenters added that credit "beyond neutral" should be considered for the use of biogas in electric production, because combusting methane converts the carbon from a higher GHG potential (meth ane) to that of CO2, combustion of methane should be recognized for its reduction in GHG potential.

Commenters stated that unlike fossil fuel emissions, biogenic CO2 emissions from all types of forest biomass

- derived fuels do not contribute to increases i n atmospheric carbon levels as long as forest carbon stocks are growing or are stable. Commenters stated that biomass combustion is one part of the continuous cycling of carbon between the atmosphere and biomass stocks. Commenters stated that carbon stocks on United States timberlands on average are growing at more than twice the rate of harvests. Commenters stated that the United States Forest Service found that the growth to removal ratio across United States timberland increased from 1.7 to 2.1 from 2006 to 2011.

Commenters stated that the EPA fails to provide adequate justification for treating biogenic CO2 emissions the same as fossil fuel emissions in the CPP despite EPA's recognition that biomass energy is renewable, "carbon neutral", and can result i n "climate benefits" when compared to fossil fuels.380 Commenters stated that the EPA has developed a comprehensive scientific, technical and legal record throughout its work on the Accounting Framework that strongly supports a clear and simple position recognizing the climate benefits of biomass

- derived fuels in the CPP. Based on the weight of the scientific evidence and data, commenters recommended that the EPA should clearly conclude that the use of forest products manufacturing residuals for energy is carbon neutral and should therefore be categorically exempt from regulation. Commenters stated that there would be little or no regulatory (de minimis) benefit from regulation of biomass CO2 under the Clean Air Act.

Commenters stated that EPA cannot lawfu lly allow states to treat biomass generation as "carbon neutral" in preparing compliance plans.

Commenters stated that the Proposed Rule also appears to allow states to treat biomass energy generation as "carbon neutral" in developing their compliance pla ns. Commenters stated this would effectively allow states to use biomass energy generation (classified as "renewable energy" under Building Block 3) to reduce fossil generation and associated emissions at covered facilities, without counting the CO2 emitte d (either at the smokestack or on a "net" atmospheric basis) by the bioenergy facilities. Commenters stated that the result could well be that states report emissions reductions from generation that actually increases atmospheric CO2 concentrations over th e time frame of the Proposed Rule. Commenters stated such a result would be arbitrary and directly contrary to the purpose of section 111.

Commenters stated that although no clear rationale appears on the face of the Proposed Rule, this approach appears to be grounded in two assertions: first, that biomass generation reduces emissions compared to fossil fuel

- fired generation because plant

- based feedstocks sequester CO2 while growing, and second, that some states have developed policy goals supporting biomas s energy. 79 FR 34924

- 34925, 34834, and 34900. Commenters stated that the first assertion is false, and the second cannot justify a decision to treat biomass generation as "zero

- carbon" renewable energy in evaluating state compliance measures.

First, the commenters asserted that to the extent EPA is relying explicitly or implicitly on the theory that biomass CO2 emissions cannot affect atmospheric concentrations because CO2 was previously sequestered during feedstock growth, that theory is entirely unsuppo rted and demonstrably incorrect. Commenters stated that combusting terrestrial carbon stocks results in a transfer of carbon to the atmosphere. Commenters stated that while trees, plants, and soils may not store carbon for as long as fossil fuel materials, trees and soils in particular can store that carbon for periods of time relevant to climate mitigation efforts

- and certainly for periods of time relevant to the Proposed Rule's 2020

- 2029 and 2030 compliance periods. Commenters stated that when that carb on is in terrestrial stocks, it is not exerting a warming effect on the climate. Commenters stated that when that carbon is oxidized to CO2, however, it does exert a warming effect. Commenters stated that infrared radiation cannot tell the difference betwe en a molecule of biomass CO2 and a molecule of fossil CO2. Commenters stated that both trap heat for as long as they remain in the atmosphere.

Indeed, taken to its logical extreme, commenters stated that this theory would lead to the absurd conclusion that deforestation has no effect on climate change. Commenters stated that under a literal application of this theory, every single tree, shrub, and blade of grass on Earth could be381 burned tomorrow and converted into CO2 with no discernible effect on the clima te, simply because those plants absorbed CO2 when they were growing.

Commenters stated that scientists and policy

- makers agree, however, that deforestation

- which necessarily entails conversion of sequestered biogenic carbon into atmospheric CO2

- does

co ntribute to climate change. Commenters stated that 10 to 15 percent of global carbon emissions result from deforestation and forest degradation, primarily in the tropics. Commenters stated that these emissions are estimated at between 1,400 and 2,000 Tg pe r year. Although U.S. forests are generally considered a net carbon sink, the commenters stated that this may be true only due to significant global leakage related to domestic demand for wood and agricultural products. Commenters stated that the United St ates has also experienced the greatest loss of forest cover, as a proportion of forest cover in the year 2000, of any country with more than one million square kilometers of forest. Commenters stated that GHG emissions associated with these losses are sign ificant contributors to climate change. Commenters stated by the same token, a wide

- scale shift to woody biomass energy generation could result in conversion of nearly all of the world's unmanaged forests and much of its pastureland to energy plantations.

Commenters stated that this theory also ignores the fact that a tremendous amount of primary forest, representing a huge proportion of historic biogenic carbon stores, has been lost during the last few centuries. Commenters noted that according to maps co mpiled by the World Resources Institute, only 21 percent of the world's forests are "intact," and 47 percent have been lost entirely. Commenters stated that between 1850 and 2000, global land use change caused emissions of 156,000 Tg of carbon, mostly from deforestation. Commenters stated that recent studies indicate that the density of remaining forest cover may be lower and far more variable than previously thought.

Commenters stated this historic and continuing loss of forest biomass

- much of which has been burned or otherwise converted into atmospheric carbon pollution

- represents a tremendous existing carbon debt, one that further emissions of biogenic carbon can only increase.

Commenters stated that the EPA should not assume that all biomass genera tion is carbon neutral. Commenters noted that while the carbon emissions from biomass are part of what is called "biogenic carbon cycle" as opposed to the "geologic carbon cycle," they still result in net increases in the levels of greenhouse gases in the atmosphere

- particularly in short

- to medium

time horizons. Commenters stated that the carbon emissions from some biomass plants are greater than those from coal plants. Commenters stated that EPA should differentiate between different biomass feedstocks a way that matches the reality and life

- cycle nature of biomass carbon emissions. Commenters stated that this would give more carbon reduction credit to those that use waste streams, and would likely result in some biomass energy applications being net
po sitive, some net neutral, and some net negative with regard to carbon emissions. Commenters stated that anaerobic digesters, for example, should get credit both for fossil

- fuel displacement and for methane destruction. Commenters stated that those methane reductions would not likely be addressed in a separate rule on methane sources.

Commenters stated that by counting electricity generated at biomass power plants toward state totals, but not counting facility CO2 emissions, the EPA is treating biomass power plants as instantaneously carbon neutral. Commenters stated this is a fundamental flaw that not only382 makes a mockery of the so

- called scientific review process that EPA employed to devise a system for biogenic carbon accounting, but also fundamentally red uces the ability of the GHG rule to reduce CO 2 emissions from the power sector.

Commenters noted that to justify the treatment of bioenergy as having zero emissions, EPA issued a memo from Acting Assistant Administrator for Air and Radiation Janet McCabe which declares that waste

- derived and forest

- derived industrial by

- products, including not just black liquor but also materials such as mill wastes, " are likely to have minimal or no net atmospheric contributions of biogenic CO 2 emissions " and hence, should be treated as having no emissions under the Clean Power Plan. Commenters noted that the memo further states that EPA will likely also exclude emissions from "sustainably harvested" biomass, thus disregarding the central conclusion of EPA's own Frame work and an abundance of peer

- reviewed science, that harvesting and burning forest wood for energy represents a large net source of CO 2 emissions that persists for decades to more than a century.

Commenters stated that invocation of "sustainable" harvesti ng in this context is practically irrelevant to biogenic carbon accounting because it is possible for multiple harvest

- to

- growth ratios to be considered "sustainable," even as they differ with regard to net atmospheric CO2 loading and carbon sequestration. Commenters stated that the concept of sustainable harvesting as stand

- in for carbon neutrality is especially meaningless in the context of Appendix D of the Framework, which outlines an approach for calculating net emissions from biogenic fuels. Commenter s stated that the approach requires comparing emissions from burning materials for energy to emissions that would occur under alternate fates, such as decomposition, or in the case of live plants harvested for fuel, alternate end fates including harvest fo r saw timber or being left to grow without harvest. Commenters stated that Appendix D makes it clear that for nearly every solid fuel typically burned for energy recovery

- black liquor being the single exception

- emissions from combustion can easily exce ed those from alternate fates, meaning that for most scenarios, burning these materials adds net CO 2 to the atmosphere over timeframes of years to decades. Commenters stated that, as the Framework makes clear, this comparative approach is the only way to d etermine the net effect of a biomass

- burning facility on atmospheric CO 2 loading. In fact, the commenters stated that the concept of "sustainable" harvesting is (appropriately) not mentioned in the Framework. Commenters provided several figures to illustr ate why "sustainability" does not correspond to carbon neutrality.

Commenters stated that the McCabe memo cites the Framework as supporting treatment of biogenic emissions as zero. However, the commenters stated under the Framework's approach, bioenergy em issions can only be considered to be net zero if sufficient time has elapsed for the difference between combustion emissions and alternative fate emissions to be reduced to zero. Commenters stated that the McCabe memo does not provide a timeframe to contex tualize the claim that biomass emissions should be counted as zero, which is a grave omission given that the GHG rule requires that power sector emission rates meet certain targets by 2020 and 2030. Thus, the commenters stated that treating emissions as ze ro under the GHG rule is arbitrary and contrary to EPA's own science and recommendations.

Commenters stated that the classes of fuels identified in the McCabe memo are nearly all

encompassing. Commenters stated there is likely no biomass burned in the US where operators wouldn't claim that the fuel was derived from "waste," industrial forestry residues, or383 "sustainably harvested" material (an easy claim to make since the term is meaningless). Commenters stated that a review of current

- day biomass sector em issions demonstrates the magnitude of the emissions that are thus ignored. Commenters stated that by EPA's own accounting, uncounted emissions from standalone biomass power plants represented about 78 million tons of CO 2 in 2012, equivalent to the entire p ower sector emissions of 13 states and Washington DC (VT, DC, ID, SD, RI, ME, NH, AK, DE, WA, OR, HI, CT, MA) as reported by the Energy Information Administration. Commenters stated that this excludes emissions from facilities that generate heat but not po wer from biomass, and therefore is a significant underrepresentation of the actual amount of uncounted emissions.

Commenters stated that EPA should clearly exempt bioenergy CO2 emissions from forest materials and manufacturing residual fuels. Commenters u rged the EPA to recognize that biogenic CO2 emissions should not be regulated under this rule or should be exempted as deminimis. Commenters suggested that this recognition should be made as a consequence of the net carbon neutral attribute of such emissio ns, which arises from the unique natural cycling of carbon between the atmosphere and terrestrial carbon sinks, such as the forests within the United States, and the ability of those forests and the timber and wood products produced from them to sequester carbon for long periods of time. Commenters noted that on balance, U.S. forests are in a long term trend of sequestering more carbon (about 2 times as much) from atmospheric CO2 than is theoretically released by their harvest for use in products and bioene rgy production.

Comment 37: Biomass in section 111(b)

- Commenters described inconsistencies in the EPA's biomass policy that affect accounting for emissions.

Response 37: The definition for affected sources can be found in Section IV.D of the preamble.

In November 2014, the agency released a second draft of the technical report, Framework for Assessing Biogenic Carbon Dioxide for Stationary Sources . The revised Framework, and the EPA’s Science Advisory Board (SAB) peer review of the 2011 Draft Framework , finds that it is not scientifically valid to assume that all biogenic feedstocks are “carbon neutral” and that the net biogenic CO 2 atmospheric contribution of different biogenic feedstocks generally depends on various factors related to feedstock charac teristics, production, processing and combustion practices, and, in some cases, what would happen to that feedstock and the related biogenic emissions if not used for energy production.

A discussion of the use of biomass feedstocks and associated biogenic CO 2 assessment can be found in in Section VIII.I and Section VIII.K of the preamble.

For more information regarding the revised Framework , see: http://epa.gov/climatechange/ghgemissions/biogenic

- emissions.html

The following are summaries of the specific pu blic comments under this comment:

Commenters said that the EPA states in the preamble that its intent is to adopt the rule "that in all other respects would meet the applicability criteria for coverage under the proposed GHG384 standards for new fossil fuel

- f ired EGUs" (79 FR 1430; January 8, 2014). 79 FR 34854 However, commenters said that the proposed rule fails to include a provision similar to that included in the section section 111(b) new source rule exempting a steam generating unit combusting fossil fu el for less than 10% of its heat input during any 3 consecutive years.

Commenters pointed to inconsistencies between the January 2014 NSPS Proposal that stated "the proposed CO2 emission standards only apply to new fossil fuel

- fired EGUs." and "[b]ased on the applicability provisions . . . an EGU that primarily fires biomass would not be subject to the CO2 emission standards." and the provisions of EPA's proposed guidelines, which appear to reverse course and negate the benefits associated with carbon

- neut ral biomass.

Commenters supported the EPA's treatment of EGUs that primarily fire biomass in its January 2014 NSPS Proposal because it encourages the use of a renewable and carbon

- neutral energy resource. Commenters noted that in comments on the January 20 14 NSPS Proposal the commenters urged the EPA to further encourage its use by excluding all biogenic CO2 emissions from an affected facility's compliance calculation. Commenters said that the exclusion of biomass

- fired operations would be consistent with 4 0 CFR 98 (the mandatory GHG Reporting Rule) that requires separate reporting of CO2 emissions from fossil fuels and biogenic sources. Commenters stated that the EPA should allow the use of the 40 CFR 98 calculation methodologies to determine a unit's bioge nic CO2 emissions for compliance with the proposal to be consistent with the metric tons of CO2 that the unit will report to the EPA under 40 CFR 98. Commenters added that "[a] long standing inventory convention adopted by the Intergovernmental Panel on Cl imate Change [IPCC], the UNFCCC [United Nations Framework Convention on Climate Change], the U.S. GHG Inventory, and many other reporting programs is separate treatment of emissions of CO2 from combustion of biomass and biomass

- based fuels from emission of CO2 from the combustion of fossil

- based products." Commenters concluded that, at a minimum, the EPA should maintain consistency with its January 2014 NSPS Proposal and include an applicability criteria that requires the combustion of fossil fuel for more than 10 % of the heat input during any three consecutive calendar years for existing steam generating units. Moreover, commenters said, the EPA should further recognize the benefits of using a carbon neutral feedstock "biomass" below a defined threshold by excluding all biogenic CO2 emissions from an affected facility's compliance calculation.

Commenters attached their October 2014 comments on the GHG proposal for modified and reconstructed EGUs. In that comment, the commenters argued that EPA should conduct a separate rulemaking that addresses how biomass units will be regulated. Commenters noted that EPA proposes to delete the low fossil use exemption for existing boilers and IGCC units. Commenters stated that this exemption applies t o units that burn fossil fuel for 10 percent or less of the heat input during a three

- year rolling period. See 79 FR 34979. Commenters noted that EPA states this exemption was "designed to exempt facilities that are capable of combusting fossil fuel, but b urn primarily non fossil fuels

- e.g., wood

- fired EGUs" Id. Commenters stated that if EPA deletes the low capacity factor exemption, existing biomass

- based units will be subject to the proposed standards for modified and reconstructed units under section s ection 111(b) . Commenters stated that these units also would become subject to regulation under section 111(d), and states would be required to address emissions from these units in state compliance plans. Commenters stated that without guidance from EPA a s to how biomass385 emissions will be addressed, it is premature to comment on the applicability requirements or standards for these units.

Commenters noted that in the modified/reconstructed EGU proposal, EPA solicits comment on whether to create a subcategory for these units in recognition of the fact that they are inherently less efficient than fossil

- based EGUs. See I d. Commenters recommen ded that, consistent with EPA's statutory obligations, the Agency should ensure that the section 111(b) standards for biomass

- based units are achievable. Commenters stated that creating a separate subcategory for these units and subjecting them to appropri ate standards would satisfy EPA's CAA section 111(a)(1) mandate that emission standards be achievable. Commenters noted that it is premature, however, to comment on what standard would be achievable as EPA has not proposed any numerical standard for these units and there are no data in the record to support any such standard.

Moreover, commenters stated that it is not possible to address appropriate standards for these units under either section section 111(b) and (d) until EPA provides guidance as to whet her certain types of biomass are carbon neutral, and, if not, how emissions from certain types of biomass will be determined. Commenters stated that as EPA notes in the preamble to the proposed 111(d) guidelines, the EPA Science Advisory Board has reviewed a draft of the accounting framework for emissions from biogenic sources, and EPA is in the process of revising the framework. See 79 FR 34924

- 25. Commenters stated that according to EPA, "the draft framework concluded that while biomass and other biogenic feedstocks have the potential to reduce the overall level of CO2 emissions resulting from electricity generation, the contribution of biomass

- derived fuels to atmospheric CO2 is sensitive to the type of biomass feedstock used, and the way in which the fee dstock is grown, processed, and ultimately combusted as a fuel for energy production." Id. at 34924. Accordingly, at this time, the commenters stated that there is no guidance and little certainty about how emissions from biomass

- based units will be determ ined and addressed.

In their comments on the modified/reconstructed proposal, commenters explained that it is difficult for stakeholders to provide meaningful comment on issues related to biomass

- based units before EPA publishes the accounting framework. Commenters stated that in addition, the fact that EPA raises issues related to the regulation of biomass emissions in multiple related rulemakings makes it difficult to assess exactly what EPA is proposing with respect to these units. Accordingly, commente rs recommended that EPA should conduct a separate rulemaking to address holistically all issues related to the regulation of GHG emissions from biomass

- based units and to afford stakeholders the opportunity to provide meaningful comment on EPA's proposed t reatment of these units.

Comment 38: Treatment of biomass suffers from flaws under the Administrative Procedures Act.

Response 38: In this rule, the EPA is not taking final agency action with respect to how biomass will be treated under 111(d) and so the commenters’ claims about the Administrative Procedure386 Act (which appear to focus on a contention that they did not have a meaningful opportunity to comment on issues related to how biomass would be treated under this rule) are not on point.

In November 201 4, the agency released a second draft of the technical report, Framework for Assessing Biogenic Carbon Dioxide for Stationary Sources . The revised Framework, and the EPA’s Science Advisory Board (SAB) peer review of the 2011 Draft Framework , finds that it is not scientifically valid to assume that all biogenic feedstocks are “carbon neutral” and that the net biogenic CO 2 atmospheric contribution of different biogenic feedstocks generally depends on various factors related to feedstock characteristics, produ ction, processing and combustion practices, and, in some cases, what would happen to that feedstock and the related biogenic emissions if not used for energy production.

A discussion of the use of biomass feedstocks and associated biogenic CO 2 assessment c an be found in in Section VIII.I and Section VIII.K of the preamble.

For more information regarding the revised Framework , see: http://epa.gov/climatechange/ghgemissions/biogenic

- emissions.html

The following are summaries of the specific public comments un der this comment:

Commenters said that the proposed rule's treatment of biomass suffers from multiple flaws under the Administrative Procedures Act.

Commenters described the East Texas Electric Cooperative's investment in a 49.9 MW biomass

fired electric generating facility located in Woodville, Texas. Commenters explained that this biomass facility is fired by forestry and lumber waste and, as such, has qualified for incentive funding under a variety of Congressional and Executive Branch initiatives over the past decade. Commenters stated the project was largely funded with federal grants and loans, and it is vitally important to them that this type of biomass facility be treated as a carbon

- neutral renewable resource under any plan limiting carbon emissi ons. Commenters stated that the Proposed Rule does not make this clear, and its treatment of biomass suffers from multiple flaws under the Administrative Procedure Act.

Commenters said the first flaw is that a critical component for treatment of biomass ( the revised biogenic accounting framework and memorandum) was not made public when the proposed rule was issued and was belatedly made public in draft form on the eve of the comment deadline. Commenters said that the revised Framework appeared to be quite different from the first draft. With only 8 business days remaining until the comment deadline, commenters said that their comments can realistically contain only initial impressions that the memorandum fosters hope that at least some biomass projects will be treated as carbon

- neutral, but that the memorandum and new draft Framework also leave much in doubt. For example, commenters said, the Framework is merely another "draft" yet to be reviewed by the Science Advisory Board and subjected to public comment. Commenters added that it is a complex and technical document that, upon further analysis, may contain details that detract from or effectively erase the hope elicited by the more general statements in the memorandum. Finally, commenters said that sustaina ble forestry practices appear to play a role, a pivotal role in some cases, that neither document illuminates except to suggest that it may vary by region and be left to the states to387 decide what is sustainable. Thus, commenters concluded, even if one adds the memorandum and the latest draft of the Framework to the conversation, the Proposed Rule says absolutely nothing about how it will affect any particular biomass project because it depends on the feedstock, the region, the rules on sustainability, and a pparently the many equations and databases that are discussed in the second draft Framework.

Commenters said a second flaw is that what the Proposed Rule says about biomass is incoherent and not susceptible to meaningful comment. Commenters said that the EPA says that biomass treatment will depend upon the Framework mentioned above and does not explain where biomass fits in its Clean Power Plan. Commenters stated that this underlying ambiguity thwarts meaningful comment because it forces the reader to spec ulate about what the EPA intended to say. For example, commenters asked, is the EPA intending to treat biomass as other renewable facilities or as its own separate category of facilities depending on the outcome of the Framework? Commenters said that there are structural indications that the EPA envisions folding biomass into renewable energy facilities, but little else is said to explain how that would be done, particularly in light of the many types of biomass facilities discussed in the first and second drafts of the Framework.

Commenters said that a third flaw is that even if the EPA's Proposed Rule is deemed authorized by the CAA in general, the EPA's exercise of that authority adverse to waste biomass would contravene Congressional intent expressed sp ecifically on waste biomass since the Energy Policy Act of 2005. Commenters noted that Congress just a few years ago specifically endorsed waste biomass by including it among the renewable energy projects eligible for incentive funding, and it is unreasona ble to assume that Congress would then intend for the EPA to treat waste biomass as something other than carbon

- neutral. Commenters added that the EPA does not explain how its treatment of biomass relates to these Congressional enactments over the last dec ade.

Commenters said that the fourth flaw is that even if the EPA's Proposed Rule on biomass does not violate specific Congressional intent on waste biomass, the Proposed Rule lacks reasoned decision making when it ignores the interests of those who justi fiably relied, and were intended to rely, upon Congressional endorsement of biomass and built waste biomass facilities. In enacting the ARRA and the other legislation since 2005, commenters said that Congress sought to spur immediate construction of the ty pes of renewable energy facilities they made eligible for the grants and bonds. Commenters said that entities such as ETEC responded to this Congressional call to action and used the bond program to fund, in part, construction of a qualifying biomass facil ity. Commenters stated that the EPA fails to even mention the role of this legislation or how the Proposed Rule would affect those private parties who relied upon the legislative incentives when they constructed waste biomass projects with the understandab le and reasonable expectation that they would be deemed carbon

- neutral by the federal government.

Commenters said that the fifth flaw is that the Proposed Rule uses a variety of dates when discussing "existing" and "new" generation and renewable energy, r equests comments on some related dates, but provides little coherent discussion of those dates or their intended use. Commenters stated that those dates, in conjunction with the various spreadsheets cited throughout the Proposed Rule, obscure the relevant effective date or dates and thus how recently constructed plants (such as ETEC's biomass plant) or soon to be constructed plants

- that are not in the 2012 baseline model

-- will be treated under the Proposed Rule. Commenters said that it is388 not clear whet her the states can use these recently completed or soon to be completed renewable plants to meet their performance targets. Commenters illustrated the confusion with an example showing how to determine how ETEC's biomass plant will be treated.

Comment 39 : RE measures in state implementation plans.

Response 39: The final rule gives states the flexibility, to use zero

- and low

- emitting resources to achieve their CO 2 emission performance rate. The measures discussed in the preamble are representative of thos e that states may consider in their plans, but are not meant to be exhaustive.

Renewable energy and demand

- side EE and other non

- BSER measures that are tied to a state plan and achieve quantified and verified MWh savings may be used to adjust a CO 2 emission rate, provided they meet the general and specific eligibility requirements for resources used to adjust a CO 2 emission rate, described in Section VIII.K. The measures must also meet the eligibility requirements and provisions related to RE and de mand

- side EE programs and projects, if applicable, and the requirements and criteria related to proper quantification and verification of MWhs from demand

- side EE savings are described in Section VIII.K. Specifically, the use of biomass, MSW, and waste to energy are discussed in the preamble in section VIII.I and VIII.K. Preamble section VIII.K discusses measures, such as vehicle electrification, that may not be used to adjust CO 2 emission rates. See section VIII.K. of the final rule preamble of the CPP for the EPA’s response to this comment.

The following are summaries of the specific public comments under this comment:

Commenters stated that the EPA should allow for renewable energy measures that displace the electricity from covered sources used for water heating and space heating to count under state compliance plans. Commenters explained that this would include geothermal heat pumps, solar heating and cooling, and other renewable energy measures that are directly displacing the electricity from covered s ources.

Comment 40: EPA should recognize biomass combustion as carbon neutral.

Response 40: In November 2014, the agency released a second draft of the technical report, Framework for Assessing Biogenic Carbon Dioxide for Stationary Sources . The revised F ramework, and the EPA’s Science Advisory Board (SAB) peer review of the 2011 Draft Framework , finds that it is not scientifically valid to assume that all biogenic feedstocks are “carbon neutral” and that the net biogenic CO 2 atmospheric contribution of di fferent biogenic feedstocks generally depends on various factors related to feedstock characteristics, production, processing and combustion practices, and, in some cases, what would happen to that feedstock and the related biogenic emissions if not used f or energy production.

A discussion of the use of biomass feedstocks and associated biogenic CO 2 assessment can be found in in Section VIII.I and Section VIII.K of the preamble.389 For more information regarding the revised Framework , see: http://epa.gov/clima techange/ghgemissions/biogenic

- emissions.html

The following are summaries of the specific public comments under this comment:

Commenters stated that the EPA should recognize biomass combustion as a carbon neutral, alternative energy source.

Comment 41: Biomass fuels are not carbon neutral.

Response 41: In November 2014, the agency released a second draft of the technical report, Framework for Assessing Biogenic Carbon Dioxide for Stationary Sources . The revised Framework, and the EPA’s Science Advisory B oard (SAB) peer review of the 2011 Draft Framework , finds that it is not scientifically valid to assume that all biogenic feedstocks are “carbon neutral” and that the net biogenic CO 2 atmospheric contribution of different biogenic feedstocks generally depe nds on various factors related to feedstock characteristics, production, processing and combustion practices, and, in some cases, what would happen to that feedstock and the related biogenic emissions if not used for energy production.

A discussion of the use of biomass feedstocks and associated biogenic CO 2 assessment can be found in in Section VIII.I and Section VIII.K of the preamble.

For more information regarding the revised Framework , see: http://epa.gov/climatechange/ghgemissions/biogenic

- emissions.h tml

The following are summaries of the specific public comments under this comment:

Commenters stated that biomass fuels are not carbon neutral.

Comment 42: The EPA should exclude biopower from targets or review how it sets targets for biomass.

Response 42: Biomass is not considered part of the best system of emission reduction in this rule and therefore it is not included in goal

- setting or compliance evaluations. However, similar to other technologies outside of BSER, biomass may be considered as a part of a state’s plan to meet the emission guidelines

. For more information regarding Building Block 3, refer to Section V.E of the preamble.

A discussion regarding the use of some biomass feedstocks for compliance purposes can be found in Section VIII.I an d Section VIII.K of the preamble.

The following are summaries of the specific public comments under this comment:390 Commenters said that the EPA should exclude biopower from targets or revise how it sets targets for biomass.

Other Generation Comments

Comme nters described other generation technologies that should be considered for compliance.

Comment 43: Include nuclear generation towards compliance.

Response 43: The EPA acknowledges the comments and has decided to treat all low

- and zero

emitting sources similarly in the final rule. As such, the BSER for the final rule will not include either of the proposed provisions for existing and under construction nuclear units in the setting of state goals. Please see section V.A. of the preamble for further discus sion of the decision to exclude nuclear power from BSER, and sections VIII.K for how incremental generation from new and uprated nuclear power is addressed in relation to other sources and as approvable actions to include in state plans.

The following are summaries of the specific comments under this comment:

Commenters believe d that it is appropriate to allow nuclear generation to count towards compliance even though it is not appropriate to include in the state goal calculation. Specifically,
commenters s tated that to incent optimal performance of this zero

- emitting resource, the EPA should allow MWhrs in excess of an 81% capacity factor to count toward compliance in the rate

based approach. Commenters stated the historical capacity factor of the existing nuclear fleet is 81% and operation above that level should be incented to help reduce emissions from fossil

- fired plants. Commenters recommended that output of plants that are relicensed after the baseline year (2012) should count towards compliance, as we ll the output of plants licensed to operate in excess of 60 years.

Comment 44 : Modernize and Improve Utility and Power Market System using Performance

- based Regulations

Response 44: This comment is outside the scope of this rulemaking. This final rule s ets emission performance goals for states based on the BSER for existing sources under CAA section 111(d). In this rule, EPA is not regulating power markets or setting rules for utility pricing. This final rule does support flexible measures to achieve CO 2 emission reductions and the increased use of zero

- and low

- emitting generation.

The following are summaries of the specific comments under this comment:

Commenters said that it is important to modernize and improve utility and power market systems using performance

- based regulations. Commenters said that changing market dynamics of the391 utility and power market systems, including technological innovations like smart grid, intelligent business processes, distributed generation and other elements empowering consumers; cost

competitive variable and other renewable energy resources; and the need to upgrade and modernize the nation's power market, transmission and distribution systems, require an updated policy framework to spur necessary private sector investme nt and development. Commenters stated this framework should support the financial integrity of utilities which act as providers of last resort, wholesale procurement that reflects a portfolio of short, medium and long term contracts financially hedged and transparency at the wholesale and retail levels. Commenters stated that the framework should also promote competitive wholesale markets and grid resiliency through the deployment of distributed and demand response resources and ancillary services. Finally, commenters said, the framework needs to ensure resource diversity, energy information standardization and ease of access, subject to privacy and security requirements.

Commenters said appropriate market price signals are essential for success and continued innovation. Commenters stated states should move away from rate

- of

- return utility regulation models, because the use of performance

- based regulations gives utilities t he freedom to innovate or call on others for specific services. Commenters said that states should separate the financial health of the utility from the volume of electricity the utility sells. In conjunction, commenters said states should ensure that all markets (e.g. energy, ancillary services, and capacity) and market

- makers (e.g. utilities) include both demand

- and supply

- side options. Commenters stated that all options (central and distributed generation, transmission, efficiency, and demand

response) should compete with one another to provide electricity services.

Commenters noted that performance

- based regulations could also employ electricity markets to align incentives with the desired outcomes, such as rewarding greater operational flexibility. As part of the transition away from fossil fuels, commenters said that states should implement debt equivalency rules which can allow PPAs used in the transitioning process to earn an equity return, thereby making the transition away from the fossil fuels mu ch more economically attractive for a utility. Commenters stated that wholesale power markets, whether vertically integrated, regulated, or publicly

- owned monopoly utilities, can also be better aligned to support a growing and large share of renewable ener gy. Commenters stated regulators and market operators have a number of cost

- effective, market

- based options to manage more base

- load and variable energy resources. Commenters said by consolidating balancing areas into larger operating areas, improving and utilizing weather forecasting, and decreasing the intervals between resource commitment and dispatch decisions, greater levels of renewables can be effectively integrated. With a greater share of renewables, commenters added, markets need to recognize the value of resource flexibility and the growing opportunity for customer loads to respond to market conditions.

Commenters recommended that the pricing of operating reserves be sharpened to more efficiently reflect short

- term mismatches between supply and d emand, allowing responding loads to participate in energy and ancillary service markets. As the share of renewables grows, commenters said that the system will require both adequate resources as well as a flexible resource portfolio. Commenters concluded t hat market administrators need to factor these elements into their forecasts and forward markets to ensure resource flexibility is considered at the point of initial investment.392 Comment 45: Mitigate the Environmental Impacts of Coal

Response 45: This comment is outside the scope of this rulemaking. This final rule sets emission performance goals for states based on the BSER for existing sources under CAA section 111(d). In this rule, EPA is not designating which technologies or resources should be inve sted in. This final rule supports flexible measures to achieve CO 2 emission reductions and the increased use of zero

- and low

- emitting generation.

The following are summaries of the specific comments under this comment:

Commenters said that the governmen t should invest in technologies that mitigate the environmental impact of coal.

Commenters noted that manufacturing relies on affordable, reliable base load energy to always be available to meet demand, and the most reliable source of that energy for the Great Lakes region is currently coal. Commenters stated that the federal government should invest more heavily in the technologies that promise to significantly mitigate the environmental impact of this competitive fuel source, especially with the reliance of many emerging economies on coal. Commenters noted that the research and development programs of the National Energy Technology Laboratory represent a major opportunity to achieve a better environment, to help developing economies mitigate their carbon problems, and to build our nation's competitive position and that these projects should be equipped with strong levels of funding. Commenters urged the EPA to Fully utilize all of our nation's energy resources and keep the Administration's pledge of an "al l of the above" energy strategy that truly seeks to maximize the net benefits of coal.

Commenters described current DOE investments in clean coal technology and advances in technology that have resulted in more efficient combustion and fewer emissions per unit of energy. Commenters said that increased efficiencies at U.S. coal plants will provide major benefits to the U.S. economy and provide a large increment of new, low

- cost, coal

- based electricity generation. Commenters stated that even moderate increase s in coal plant efficiencies would increase total U.S. coal electricity generation by about 11%, reduce CO2 emissions by 250 million tons, and create 250,000 jobs. Commenters stated that now is not the time for the U.S. to abandon leadership in 21st Centur y Coal, but the Proposed Rule threatens to do exactly that, by directing investment away from coal. Indeed, commenters said, the Proposed Rule does not even analyze investing in low

- carbon technology as a regulatory alternative at all. Commenters concluded that a more rational approach would use 21st Century Coal technologies to ensure prosperity and economic growth around the world.

Commenters described their MicGAS coal biotechnology process that uses termite

- derived microbes to convert mined coal in ana erobic bioreactors to hydrogen

- rich methane biogas, carbon

- rich actosol organic humic liquid for agriculture use, and HUMASORB, a solid co

product that can be used to adsorb (i.e., remove) toxic contaminants from wastes and waters. For unmineable coal seam s, commenters stated that bioconversion occurs in the seam itself and the biogas can be recovered gradually. Commenters stated this biotechnology utilizes every393 component that makes up coal. Commenters stated that even heavy metals, such as mercury and

ars enic, which must be captured in thermal coal conversion processes, remains part of the solid

co

- product; these metals remain permanently bound and are not released. Commenters added that no process wastes are generated, and one of the main products, methan e, can be used to generate electricity or converted to other low

- carbon liquid fuels or chemicals. Commenters asserted that MicGAS Coal Biotechnology and its products are successfully being demonstrated and are ready for deployment for both new and existin g coal plants for compliance with the proposed rule as well as the Cross

- State Air Pollution Rule and Mercury and Air Toxics Standards for Power Plants. Commenters stated that this approach offers an opportunity to comply with these mandates without increa sing costs but rather increasing economic value from coal use, while helping increase the supply of safer foods, waters and wastes disposition. Commenters said that adoption of carbon rich humic products made from coal offers the coal and mining industry a chance to cost effectively manage the wastes and acid mine water discharges and overcome the concerns from mining the coal. Commenters added that it also extracts clean fuel from stranded coals otherwise unmineable by using our MicGAS in situ approach. Co mmenters noted that the US Geological Survey estimates that there are about 9.5 trillion tons of coal resources in the US (including Alaska), but the vast majority of these resources are not economically and/or technically recoverable.

Commenters stressed the importance of proper accounting and incentives to encourage projects such as combusting methane from coal mines and purchasing the resulting energy. Commenters were concerned that since their Colorado coal mine project was installed after 2012, it mig ht count as a carbon increase rather than the major decrease in greenhouse gas emissions that it will actually have. Commenters feared that this could limit how many other utilities and investors take on projects of this sort, and stated they wouldn't want to see that happen.

Commenters noted that North Dakota lignite provides a majority of the electricity available in North Dakota and that North Dakota has determined that its electrical demand will continue to grow substantially related to oil and gas deve lopment, population growth and new ancillary business development. Thus, commenters said that new efficient lignite

- fueled baseload electric generation facilities should not be removed as an available option by any EPA regulatory action nor should well mai ntained existing lignite fueled facilities be curtailed or closed. Commenters supported research and development efforts to ensure the future of lignite for years to come and the EPA must allow promising GHG reduction technologies to "come into their own."

Comment 46: Mitigate the Environmental Impact of Oil and Natural Gas Generation, including geothermal.

Response 46: This comment is outside the scope of this rulemaking. This final rule sets emission performance goals for states based on the BSER for ex isting sources under CAA section 111(d). In this rule, EPA is not extending the scope to address oil and gas production. This final rule does support flexible measures to achieve CO 2 emission reductions and the increased use of

zero

- and low

- emitting gene ration.

The following are summaries of the specific comments under this comment:394 Commenters described the potential for coproduced geothermal power in old oil fields across the western states and throughout the world to decrease the demand of electricity f rom the oil and gas sector.
Commenters noted that oil and natural gas fields produce an average of 25 billion barrels of hot water annually, which could translate into over 3 GW of electricity. Commenters added that the number of old oil and natural gas w ells identified to have geothermal potential numbered at over 80,000 in 2012. Historically, commenters said, this hot water has required costly disposal; however, it is now being considered as a potential resource that can be used to produce electricity fo r field operations or sold to the grid. Commenters stated that many oil & natural gas fields have transmission infrastructure already in place, which could be inexpensively upgraded. Commenters stated these co

- produced geothermal resources can deliver near

- term energy savings, diminish greenhouse gas emissions, extend the economic life of oil and natural gas fields, and profitably utilize abandoned oil and natural gas field infrastructure. Commenters noted that these small co

- produced fluid units are mobile and unmanned, and they can be set up in days or weeks, and moved as new wells are drilled. Commenters stated that there are fully packaged, commercial units that have varying outputs depending on flows and temperatures of each well, and can be a cleaner a nd affordable alternative to diesel generators. Commenters said that one of the riskiest and most expensive steps during any geothermal power project occurs at the beginning when initially searching for geothermal resources. Before a developer can even beg in construction, commenters said, they will usually spend 50

- 60% of the project's total costs on exploration and drilling activities. Commenters added that unfortunately, co

- producing geothermal resources on federal oil and natural gas leases is currently not accommodated by the Mineral Leasing Act and Geothermal Steam Act of 1970 which require competitive bidding for all geothermal leases. However, commenters said, these technologies are still feasible where oil and gas is produced on state and private lan ds.

Comment 47: Beyond the fence carbon offsetting for bioenergy under the GHG rule

Response 47: A discussion regarding the use of some biomass feedstocks for compliance purposes can be found in Section VIII.I and Section VIII.K of the preamble.

Out

- of

- sector offsets may not be counted toward meeting a CO 2 emission performance level for affected EGUs or a state CO 2 goal, because out

- of

- sector offsets are not connected to the electrical grid and so cannot reliably address stack CO 2 emissions from a ffected EGUs. See Section V.B.3 and VIII.K.1 of the final rule preamble of the CPP. However, state plans may accommodate emission budget trading programs that may include out

- of

- sector GHG offsets, which we are finalizing as an option under the state measu res plan type. See Section VIII.J.2.d of the final rule preamble of the CPP.

The following are summaries of the specific comments under this comment:

In a 2014 technical memorandum titled "The Role of Biomass Energy in EPA's Greenhouse Gas Rule; Final Revi sion" attached to a comment, commenters questioned if "beyond the fenceline" carbon offsetting for bioenergy is allowable under the GHG rule.395 Commenters stated that extensive use of "beyond the fenceline" mitigation measures for reducing greenhouse gas em issions is certain to become an issue of contention, as EPA has recognized in its request for comments. [79 FR 34888] Commenters stated that while the NSPS rule treats an individual power plant as the entity of concern, setting a fixed emissions standard
t hat applies at the facility, the ESPS seeks a "best system of emission reduction" (BSER) for entities where the boundaries are less clear. Commenters stated that questions such as the following will be extensively argued and likely litigated:

• Does increase d use of low

- or zero

- emissions renewable energy (EPA's terms) somewhere in a state constitute a "reduction" in greenhouse gas emissions from that state's coal

- fired plants?

• Can increased demand

- side efficiency likewise constitute a reduction?

Meanwhile, the commenters stated that it is important to recognize that most claims for bioenergy as having "low" or "zero" carbon emissions also rely on "beyond the fenceline" mitigation. Commenters stated that biomass can't play a role in reducing greenhouse gas

em issions at the time it is burned, because essentially all biomass fuels emit more CO 2 per unit energy generated than all fossil fuels. Thus, the commenters stated that any claim that bioenergy emits less CO 2 than fossil fuels relies on calculation of net C O 2 emissions over time. Commenters stated that lifecycle GHG accounting can show lower net emissions for biomass than for fossil fuels, based on either the idea that fuels are waste that would decompose and inevitably emit CO 2 anyway, or that fuels are sou rced from forests or crops that can regrow and sequester an equivalent amount of CO 2 as emitted by burning. However, the commenters noted that as neither process is instantaneous, no biomass energy can be instantaneously carbon neutral.

In fact, the comme nters asserted that both justifications for eventual carbon neutrality of biomass energy are essentially carbon offset schemes, in that they assume that a process occurring in some other place, and at some future time, compensates for CO 2 emissions from bu rning biomass now. The commenters asked:

• Can the GHG rule accommodate a scenario whereby it is acceptable to increase power plant or grid

- wide emissions by substituting biomass for fossil fuels, based on the idea that emissions will eventually be offset?

• Does EPA have the jurisdiction under the GHG rule to discriminate between stack emissions at the present time

- which for every biomass fuel are greater than emissions from coal, per megawatt

- hour

- and "net" emissions in the future, which are calculated assuming that emissions are offset?

In a narrower context, but also pertaining to Clean Air Act implementation, the commenters stated that the US Court of Appeals has weighed in on EPA's previous decision to ignore biogenic CO 2 in pollution permitting. Wh ile the Court's ruling against EPA's deferral of biogenic CO 2 regulation was based on the finding that EPA had not properly justified the decision, the commenters noted that a concurrent opinion issued with the main ruling also explained that the Clean Air Act forecloses any "offsetting" approach

- i.e., taking off

- site carbon sequestration into396 account as a compensating factor that can mitigate a power plant's emissions

- because " The statute does not allow EPA to exempt those sources' emissions of a cover ed air pollutant just because the effects of those sources' emissions on the atmosphere might be offset in some other
way ."

Commenters stated that the EPA appears to have rejected actual carbon offsets as a means of mitigating power sector emissions under the GHG rule, whereby, for instance, a forest and its carbon sequestration capacity is preserved to compensate for a fossil fuel plant's CO 2 emissions. Commenters stated that the ESPS rule is initially somewhat ambiguous as to whether the GHG rule allows offsets, but, an assessment included in a technical support document seems to clearly prohibit use of offsets for mitigation:

" For emission budget trading programs that regulate EGUs and include offsets, which we define here as emissions reductions from s ources not regulated by the trading program, emissions reductions from offsets would not be counted when evaluating CO 2 emission performance of affected EGUs, because those reductions would not come from those affected EGUs "

Commenters stated that the pro hibition on use of offsets provides a parallel for bioenergy emissions offsetting. Commenters stated that if EPA does not intend to allow actual offsets under the rule, then it is hard to see how biomass emissions that rely on offsite regrowth of fuels can be allowable, especially when most power plant operators do not own or otherwise control the forest lands where future carbon sequestration is ostensibly to occur.

Commenters stated that the situation with regard to "waste" materials that would decompose anyway may be more ambiguous. Commenters stated that the offsetting of emissions from burning true wastes simply relies on time, and the assumption that decomposition would be emitting greenhouse gases anyway if the material were not burned for fuel. In t his case, the commenters noted that as decomposition can take years to decades, and net emissions from biomass burning will almost always exceed "anyway" emissions from decomposition over multiple years, the question is simply whether the ESPS rule can cou nt hypothetical reductions in emissions that will occur at some future time as a real reduction in emissions now.

Comment 48: Comments that SIPs should give affected EGUs voluntary flexibility to determine how to achieve emission reductions.

Response 48: The states have flexibility and a wide range of measures available to choose from, but that are not mandatory. Allowable measures include those used in calculating the BSER and many more that were not part of the BSER calculations; those that are located at the affected EGU and those that are beyond the affected EGUs. Both widely deployed technologies and “innovative” technologies are allowed and supported by this rule as long as they reduce CO 2 emissions from affected EGUs and meet other state plan requir ements. The final rule gives states the flexibility to use zero

- and low

- emitting resources to achieve their CO 2 emission performance
rate. The use of non

- affected CHP generating capacity is discussed in preamble section VIII.K. The measures discussed in t he preamble are representative of those that states may consider in397 their plans, but are not meant to be exhaustive. For more information on state plan measures, see preamble sections VIII.I

- VIII.K.

The following are summaries of the specific comments unde r this comment:

Commenters stated, while the States and EPA are prohibited from imposing binding GHG emission reduction obligations on any entities other than affected EGUs, see Section VIII., supra, if EPA goes forward with the rule, the commenters agree that States should have flexibility to incorporate voluntary opportunities to reduce net GHG emissions that are broader than those used in the BSER analysis. Commenters said, to establish a feasible and cost

- effective State implementation plan, States must give affected EGUs the flexibility to incorporate low

- cost emission reductions that can be accomplished by electricity consumers or other third parties who are taking action to reduce net GHG emissions. Commenters said, at the same time, however, EPA and the States must always make clear

- both in these regulations and in State implementation plans

- that third

- party participation in such emission reduction programs is on a voluntary basis. Commenters said, by making participation voluntary, EPA and the St ates can ensure that no third

- party entity inadvertently becomes subject to regulatory obligations without its consent. Commenters said, thus, any legally binding monitoring and verification obligations that are necessary for third

- party participation in t he State implementation process will only be incurred by those entities that evaluate the participation costs, determine that the overall impact of participation is beneficial, and voluntarily assent to those legal obligations.

Commenters stated, in contra st to the BSER analysis conducted by EPA and the States, which must focus exclusively on affected EGUs, existing fossil fuel

- fired EGUs should be given broad flexibility to look beyond the fence line to identify opportunities to reduce GHG emissions throug h voluntary agreements with other entities. Commenters said, providing affected EGUs with such flexibility, where available and appropriate, in achieving GHG emission reductions is economically efficient and will allow existing facilities to reduce CO2 emi ssions through lower

cost emission reduction opportunities that can be adopted voluntarily by third parties. Commenters said, while the form would likely vary between State plans, a central feature must be the ability for entities other than affected EGUs to voluntarily participate in the program alongside affected EGUs, either by joining a centralized exchange program or through direct agreements with individual EGUs. Commenters said, in either context, the third parties would be able to choose to obtain c ompensation for taking voluntary, cost

- effective measures to reduce GHG emissions. Commenters said, the end result, which is cost

- effective emission reductions, is consistent with the general theme of the Clean Air Act because it sets emission standards th at are achievable inside the fence line of the facility without dictating how a specific facility must achieve them. Commenters said, it is also consistent with Section 111(d) specifically because it takes into account the cost of achieving emission reduct ions.

Commenters urge d EPA and the States to incorporate as broad a position as possible with respect to such voluntary compliance mechanisms to identify low

- cost opportunities to reduce GHG emissions. Commenters agree d with EPA that electricity transmissi on and distribution efficiency improvements, the use of biomass

- derived fuels, and new NGCC units should be available as voluntary compliance options that can be included in State implementation plans. See 79 Fed. Reg. at 34,923. Commenters said, to the ex tent that new, cost

- effective technological advances occur, new emission control technologies could also be included. See I d. Commenters said, in398 addition, once they are appropriately removed from the BSER analysis, the emission reduction opportunities ide ntified by EPA in Building Blocks 2

- 4 would remain eligible from a compliance perspective on a voluntary basis. Commenters said, thus, deviations from least

- cost dispatching, new renewable and nuclear generating capacity, and demand

- side energy efficiency improvements would all be eligible for voluntary participation in a State implementation plan. Commenters said, for example, performance

- based contracts ("PCs") for energy savings would offer a proven mechanism for reducing electricity consumption and lowe ring GHG emissions. Commenters said, under a PC arrangement, energy service companies ("ESCOs") install new energy efficiency equipment at customer facilities which are paid off over time with the resulting savings from the customers' utility bills. Commen ters said, EPA should expressly authorize States to include PCs as a compliance option and provide clear guidance on how States could incorporate PCs into their implementation plans. Commenters said, further, as explained in Section XII., supra, any indust rial CHP units that are excluded from the rule's applicability criteria would also be eligible to participate on a voluntary basis. Commenters also urge d EPA to look beyond the sources identified thus far and explicitly endorse carbon offsets as a viable, low

cost method of reducing net GHG emissions for voluntary participants. Commenters said, finally, to the extent feasible, States should have the flexibility to incorporate existing GHG reduction programs into their State implementation plans, provided, a gain, that no additional obligations are imposed on entities other than affected EGUs.

Commenters believe d that EPA's proposal to give affected facilities the flexibility to reduce GHG emissions through voluntary partnerships with third parties can serve a s a model for other programs under the Clean Air Act. Commenters said, in other instances, the Clean Air Act gives regulated sources broad flexibility to achieve emission reductions once EPA sets an emission limit based on the relevant legal standard. Comm enters said, thus, even when an emission limit is derived from a technology

- based standard such as the best available control technology ("BACT") standard under the PSD program, a facility is simply assigned an emissions limit, and is not obligated to inst all the technology on which the permitting authority relied so long as the facility does not exceed its assigned emission limits.

Comment 49: Commenters stated EPA should not characterize any energy technology as "best" for reducing emissions if its appli cation would undermine other emissions

- reducing technologies. Commenters said by proposing to encourage state governments to include nuclear power plants in their compliance plans, the EPA sets a policy that undermines the agency's own goal of achieving su bstantial carbon reductions in the energy sector. Commenters said with re

dispatch, an allowance system or tradable emission rate system would provide incentives for sources to reduce their emissions as much as possible, including through substituting for their generation with generation from renewable energy. Commenters said owners of existing nuclear units and nuclear units currently under construction can take action to complete or preserve that capacity, the generation from which likewise can be dispatc hed in a coordinated manner to substitute for fossil fuel

- fired generation. Commenters said coordination of these decisions in the integrated electricity system can occur through a variety of mechanisms, some centralized and some not. Commenters said nucle ar reactors are very inflexible and a poor complement for variable solar and wind generation, the two most plentiful renewable resources in the United States. Commenters said by encouraging states to devote their scarce resources to support of399 outdated and very expensive centralized nuclear power plants, the EPA would undermine the states' agility and resourcefulness in modernizing their electricity sectors and thereby maximizing carbon emission reductions. Commenters said EPA would diminish the great promi se for carbon emissions which lies in the transition, now underway, from the 20th Century system of large, centralized baseload power plants to a 21st Century system of distributed resources with actively managed demand in which low

- carbon renewable energy and efficiency play a crucial role. Commenters said subsidies to nuclear energy yield much smaller returns than subsidies to renewables. Commenters said if the states follow EPA's lead in dealing with nuclear compared to other non

- carbon resources, they w ould unnecessarily raise the cost of carbon abatement. Commenters said EPA should correct these mistakes in promulgating the final rule, which would help the states avoid those same mistakes.

Commenters stated EPA's inclusion of nuclear power in the CPP i s based on flawed reasoning, and preserving at

- risk plants and/or building new plants are not cost

- effective methods of achieving carbon emission reductions.

Response 49: The EPA acknowledges the comments and has decided to treat all low

- and zero

emittin g sources similarly in the final rule, including nuclear power plants. The final rule gives states the flexibility to use zero

- and low

- emitting resources to achieve their CO 2 emission performance rate. The measures discussed in the preamble are representa tive of those that states may consider in their plans, but are not meant to be exhaustive.

The BSER for the final rule will not include either of the proposed provisions for existing and under construction nuclear units in the setting of state goals. Plea se see section V.A. of the preamble for further discussion of the decision to exclude nuclear power from BSER, and sections V.A and VIII.K for how incremental generation from new and uprated nuclear power is addressed in relation to other sources and as a pprovable actions to include in state plans.

Comment 50: Also, unlike its proposed rule for new sources, c ommenters remarked, EPA's Proposed Rule for existing sources ignores the differences between coal

- and natural gas

- fired EGUs, and, indeed, the reasons that EPA rejected a single source category for new sources are even more compelling in regard to existing sources. Commenters continued, stating that although there are important differences in the control technology for new coal

- fired and NGCC EGU s, entities seeking to construct new electricity generation units generally at least can make a choice between the two but no such choice exists for existing units, and operators of existing sources are far more limited in the types of pollution controls o r operational parameters that may be employed to control CO2

Response 50: For the EPA’s response to this comment, see section V.A of the final rule preamble of the CPP. Section VI of the preamble addresses subcategory

- specific emission performance rates f or Fossil Fuel

- Fired Electric Steam Generating Units and Stationary Combustion Turbines.

Comment 51: Commenters supported EPA's system

- wide approach of looking "outside the fence line" with respect to setting the individual state emission targets and allow ing the option in400 state 111(d) plans. Commenters said going "outside the fence" gives states and sources the flexibility to use compliance mechanisms such as RE that go beyond sole reliance on building blocks l and 2 in order to meet their CO2 reduction go als. Commenters said inclusion of building block 3 provides the needed flexibility in states compliance plans and takes advantage of cost

effective, readily available RE generation that can also help decrease our reliance on natural gas power generation. C ommenters said WTE plants are able to supply much needed base load renewable electricity as WTE facilities routinely and continuously operate at greater than 90% of available annual capacity higher than many forms of RE production. Commenters said excludin g building block 3 could also upend state REC and RPS programs that have proven effective in shifting power generation to RE sources and reducing carbon intensity of power sector. Commenters said the opportunity for RE to reduce the carbon intensity and fo ssil fuel use of the nation's power sector is one of the most important aspects of the rule. Commenters said they fully support inclusion of existing and new renewables, including WTE, both to establish state goals and as a compliance option in state plans . Commenters supported the flexibility EPA is affording states to define what RE is and how it is used in a state plan that can build on current state REC/RPS policy and programs.
Response 51: Renewable energy sources are part of the BSER. A discussion of BSER can be found in Section V of the preamble. Section V.E of the preamble discusses renewable energy as a part of Building Block 3.
Biomass is not considered part of the best system of emiss ion reduction in this rule and therefore it is not included in goal

- setting or compliance evaluations. However, similar to other technologies outside of BSER, biomass may be considered as a part of a state’s plan to meet the emission guidelines

. A discussi on regarding the use of some biomass feedstocks, including
waste

- to

- energy, for compliance purposes can be found in VIII.I.2.c and Section VIII.K.1 of the preamble.
A discussion regarding the use of incremental renewable energy sources post

- 2012 can be fou nd in Section VIII.K.
A discussion regarding RECs and ERCs can be found in Section VIII.K.3.

Comment 52: Comments stating that one option is to couple renewable energy projects with electric boilers installed at industrial facilities that produce and cons ume large quantities of steam for process needs other than electrical generation or at affected EGUs.

Response 52: The EPA addressed RE integration in section V.E of the preamble to the final rule. The EPA also addressed co

- location of RE and affected EGUs in V.E, VIII.I and the GHG Mitigation TSD.

The following are summaries of the specific public comments under this comment:401 Commenters stated the CPP must include consideration of RE, following the approaches outlined in building block 3. Commenters said responses to integration issues will be necessary to realize the full value of emissions reduction from existing plants through deployment of RE, and to minimize cost impacts of the CPP. Commenters said this provides opportunity for solar to be combined wi th fossil fuel

- fired plants to contribute to a BSER based on a combination of blocks 1 and 2. Commenters said these hybrid facilities can produce power and ancillary services at any time using the optimal fuel mix, while increasing increase the plant's ele ctrical output or reducing fossil fuel consumption.
Commenters said that one solution for demand side power management is to couple renewable energy projects with electric boilers installed at industrial facilities that produce and consume large quantitie s of steam for process needs other than electrical generation. Commenters stated that typical examples of these types of facilities are food plants, ethanol plants, oil refineries, and paper mills. If existing base load steam production is generated from c arbon sources (i.e. gas, oil, coal), commenters said that electric boilers could be tied into an existing steam plant. Commenters stated electric boiler load could be managed using a wattage setpoint from the electric utility. As renewable power becomes av ailable, commenters said, the electric boilers wattage would be increased producing more steam which would displace production from base load carbon fuel generation. Conversely as renewable power availability decreases, commenters added, electric boiler wa ttage would decrease and base load steam generation would increase to meet steam demand. By allowing electrical load to be managed by the utility, commenters concluded that increased flexibility would lead of greater stability of grid operation.

Comment 53: Commenters requested that the following option(s) (among others) be implemented to improve the workability of the proposed guideline rule and to provide additional compliance flexibility to meet the emission targets established in the proposal:

• EPA must move forward expeditiously to provide clarity regarding the treatment of emissions from biomass for purposes of this rule. States should be able to use biomass

- based units, including co

- fired units, for compliance purposes. EPA should clarify that was te wood and forest residuals be considered carbon neutral for purposes of this rule and in any future biomass accounting framework.

• Existing nuclear units that are relicensed beyond 60 years should count as new, non

emitting units in the compliance calc ulation.

• Relicensed existing hydro should likewise be treated as new hydro for compliance calculation purposes. Incremental increases from existing hydro should also be eligible to count towards the compliance calculation.
Commenters requested that the following option(s) (among others) be implemented to improve the workability of the proposed guideline rule and to provide additional compliance flexibility to meet the emission targets established in the proposal:402 • EPA should explicitly allow the use o f co

- firing as a compliance option. However, since

co

- firing is extremely costly and not applicable to all existing coal

- fired units, EPA should retain the determination made in the proposal that co

- firing is not BSER.
Commenters requested that the follow ing option(s) (among others) be implemented to improve the workability of the proposed guideline rule and to provide additional compliance flexibility to meet the emission targets established in the proposal:

• States should have the option of whether or not to include new NGCC units in their compliance calculations. While including new units could be an important compliance option for states with emission rate targets higher than the standard EPA has proposed for new units, it could impose what are alread y significant compliance challenges for states like Virginia and North Carolina with emission rate targets that are below the standard EPA has proposed for new NGCC units.
Response 53: Renewable energy, including hydro power, and demand

- side EE, nuclear p ower, and other non

- BSER measures that are tied to a state plan and achieve quantified and verified MWh savings may be used to adjust a CO 2 emission rate, provided they meet the general and specific eligibility requirements for resources used to adjust a C O 2 emission rate, described in Section VIII.K. The preamble mentions a number of specific allowable measures that commenters asked the EPA to consider including energy efficiency, transmission and distribution improvements, CHP, nuclear power, hydroelectri c power, and biomass. Preamble section VIII.K discuss measures, such as CO 2 emission reductions from outside of the power sector that may not be used to adjust CO 2 emission rates.

The measures must also meet the eligibility requirements and provisions rela ted to demand

- side EE programs and projects, if applicable, and the requirements and criteria related to proper quantification and verification of MWhs from demand

- side EE savings are described in Section VIII.K.

New NGCC units are subject to the standard s set for new sources in the section section 111(b) final rule. They are not affected EGUs under this section 111(d) final rule and are not allowed to be used for adjusting CO2 rates of affected EGUs. For the EPA's response to this comment see sections V.A, VII.D, and VIII.K.1.b of the final rule preamble of the CPP

.

3.12 OTHER

This section addresses comments received on topics relevant to Chapter 3, GHG Mitigation Measures, which are not covered in sections 3.1 through 3.11. Topics covered by this section include broad concerns regarding the four building blocks and comments covering both renewable energy and energy efficiency. Responses to the comment topics of this section are discussed below along with summaries the specific public comments.403 Com ment 1: Commenters expressed the need for a flexible approach.

Response 1: For the EPA’s response to this comment, see sections V.A and V.B of the final rule preamble of the CPP.

The following are summaries of the specific public comments under this comme nt:

Commenters urged simplification of the proposed rule. Commenters believed that a truly flexible approach that requires a 30% reduction in carbon dioxide emissions

– however that happens

– would be more efficient than the proposed building block approac h. Commenters stated that it would allow utilities to reduce emissions using the most efficient and cost effective methods rather than trying to work within the constraints of questionable building blocks that may or may not result in lower emissions

.
Com menters stated that the proposed rule should be limited to “inside

- the

- fence” emission reductions such as power plant heat rate improvements and other onsite measures, consistent with EPA’s interpretation of the term BSER. However, commenters also stated t hat once a level of emission reduction has been determined “inside

- the

- fence” of power plants, states and utilities should have flexibility in using “outside

- the

- fence” measures for achieving these measures.

Comment 2: Commenters expressed broad concerns regarding the estimated benefits of the individual building blocks proposed.

Response 2: For the EPA’s response to this comment, see sections V.A, V.C, V.D and V.E of the final rule preamble of the CPP and chapters 2

- 4 of the GHG Mitigation Measures TSD fo r CPP Final Rule.

The following are summaries of the specific public comments under this comment:

Commenters believed that EPA based its proposal on flawed information and assumptions for the Building Blocks that will make each Block extremely difficult to achieve.

Commenters stated that these faulty underlying assumptions are extremely concerning because if, for instance, coal units cannot improve their thermal efficiency by an average of six percent, or pipeline and transmission infrastructure cannot be c onstructed in time, or EPA's energy efficiency goals prove to be untenable, states will have to rely upon other measures in order to reach their emissions reductions target. Commenters stated that this will likely entail even greater premature retirements of coal units than what EPA's Integrated Planning Model (IPM) already expects to take place.

Commenters stated that on its face, the Proposed Rule appears to be focused solely on the existing EGUs that are injecting vast amounts of CO 2 into the atmosphere, but this is not the case as EPA recommends a portfolio of four building blocks as the Best System of Emission Reduction (BSER). Commenters stated that while the building blocks will help reduce CO 2 emissions, commenters found that EPA must place more emphasis on accomplishing CO 2404 emission reductions from existing EGUs and address proactively some building blocks whose use could manifest some unexpected environmental issues.

Commenters stated that EPA should reduce unreasonable expectat ions of coal

- fired unit heat rate improvements, re

- evaluate re

- dispatch assumptions for natural gas units based on net dependable generating capacity (average of summer and winter values), allow states to determine their own renewable energy targets, and r e

- evaluate the level of demand

- side efficiency improvements required on a state

- by

- state basis.

Commenters requested that EPA review the Building Blocks and revise them to create achievable state emission reduction goals.

Commenters stated that all four b uilding blocks that serve as the foundation of the plan are unrealistic or misinformed. Commenters stated that the EPA's proposal overstates the efficiencies that can be achieved by coal plants and overestimates the ability of natural gas plants
to run at 70 percent capacity factors. Commenters also stated that the EPA assumes renewable power and energy efficiency goals that are well above achievable levels in the given compliance timeframe. Lastly, commenters added that the compliance timeline to meet the stringent 2020 goals is unreasonable considering that state implementation plans will not be finalized and approved until 2018 or 2019. Commenters asked that EPA rework the proposal to include more realistic targets and timelines

.
Commenters believed that the estimated benefits of the individual building blocks as outlined in the plan are overstated. Therefore, commenters stated that the overall goals should be reduced to reflect a more realistic evaluation of potential reductions. Commenters also stated t hat the building blocks are not grounded in real world application, and that the EPA should reevaluate the building blocks, particularly numbers 1 and 2, and recognize that the estimated carbon reductions from those building blocks are likely not achievabl e

.

Comment 3: This comment related to goal setting, particularly need for adjustments later if assumptions relied upon in setting the goal prove incorrect or unattainable due to unforeseen circumstances.

Response 3: For the EPA’s response to this comme nt, see section V.D of the final rule preamble of the CPP.

Comment 4: Commenters supported the proposed Building Block approaches in setting state goals.

Response 4: For the EPA’s response to this comment, see sections V.C, V.D, and V.E of the final rule preamble of the CPP.

The following are summaries of the specific public comments under this comment:405 Commenters supported EPA's Building Block approach in setting each state's goals and the BSER as they believed it can catalyze energy efficiency and renew able energy deployment while providing opportunity and flexibility for the electric power sector to determine the optimal way to invest in renewable resources and grow the economy.

Commenters detailed their specific plan to comply with EPA's Building Block approach which focuses on solar PV additions as their preferred strategy to comply with the proposed targets.

Comment 5: Commenters supported renewable energy and energy efficiency measures.

Response 5: For the EPA’s response to this comment, see sections V.A and V.E of the final rule preamble of the CPP.

The following are summaries of the specific public comments under this comment:

Commenters supported Building Blocks 3 and 4 as they believed that the Rule needs to incentivize energy efficiency a nd renewable energy measures in order to reduce emissions and shift to a clean energy society.

Commenters noted that energy efficiency and renewable energy measures can play a key role in reducing the rate of demand growth, supporting sustained economic di spatch of clean sources of generation before oil and coal, and minimizing the impacts of seasonal peak demand and constraints on natural gas transmission systems.

Commenters stated that the Clean Power Plan can provide utilities and energy service compani es long

- term investment certainty and can accelerate recent trends by setting targets and compliance options that fully reflect opportunities for deployment of renewables and energy efficiency. Commenters suggested that even with the technology available t oday, energy efficiency and renewable energy provide greater opportunities than EPA has taken into account in its draft targets and urged EPA to increase the ambition of its 2030 goal by relying on efficiency and renewables to make up the difference.

Comme nters encouraged EPA to strengthen its assumptions of renewable energy and energy efficiency to reflect resource availability and demonstrated market realities rather than the averages of current state mandates.

Commenters stated that Energy Efficiency is the cheapest compliance option, and that renewables are cost competitive with new coal and natural gas generation

. Commenters asked that BB3 and BB4 remain a core staple of the four building blocks, enabling growth of non

- polluting technologies as strate gies to achieve emission reduction in the proposed plan

.
Commenters stated that the Rule should increase the emphasis on development of renewable energy since these sources are growing while the cost of implementing them has declined406 dramatically and is o ften much cheaper than power from coal. Commenters urged EPA to ensure that renewable energy and energy efficiency in more fully considered in the final Rule.

Commenters strongly believed that significant improvements can be made to ensure increased carbon reduction from building blocks 3 and 4

- renewable energy and energy efficiency. Commenters also believed that the overall reduction goal is too low, and that the rule could remain achievable and be strengthened to reduce carbon emissions by at least 40 p ercent by 2030 from 2005 levels.

Comment 6: Commenters expressed concerns with renewable energy and energy efficiency

measures.
Response 6: For the EPA’s response to this comment, see sections V.A and V.E of the final rule preamble of the CPP and chapter 4 of the GHG Mitigation Measures TSD for CPP Final Rule..

The following are summaries of the specific public comments under this comment:

Commenters stated that renewable energy and energy efficiency projects are uncertain

as technology barriers and prohib itive costs make it doubtful these options will be reasonably available in the near future.

Commenters stated that EPA has not undertaken the technical or economic analyses required to adjust the Building Block 3 and 4 methodologies

.
Commenters stated tha t BB3 and BB4 should not be part of the standard

- setting process, and early actors should not be penalized for their leadership in those areas

. Commenters stated that there is no factual or legal basis for the proposed regulation's use of BB3 and BB4 reso urces to set the mandatory goals. Commenters stated it is EPA's use of these building blocks that unlawfully and unreasonably produces a standard for existing facilities in their state that would be more stringent than the standard for brand new facilities

. Consequently, commenters stated that BB3 and BB4 cannot be used, as suggested by the NODA, to drive down emission targets even further

. Commenters strongly opposed modifications to how EE and RE are mathematically accounted for in the rule. Commenters s tated that the only "benefit" of this modification is to magnify the impact of EE and RE. Commenters asserted that the rule, as presently proposed, already will be challenging to meet. Commenters stated that making a change to have RE and EE offset thermal generation and emissions only serves to lower the targets without affecting actual emissions. Further, commenters stated magnifying RE and EE will decrease flexibility in the proposed rule and make compliance more difficult. Commenters said where a state or states decide to shift away from RE and EE included in the EPA baseline in favor of, for example, reducing coal

- fired generation with more natural gas, such action will be less impactful under the new math. Commenters concluded by stating that this outc ome doesn't appear to be in line with incenting coal

- fired generation to become a smaller contributor to the U.S. power grid.407 Comment 7: Commenters suggested that certain fuels or measures be favored over others.

Response 7: For the EPA’s response to this comment, see sections V.A and V.B of the final rule preamble of the CPP.

The following are summaries of the specific public comments under this comment:

Commenters stated that coal, nuclear, and natural gas should not be favored in the Proposed Rule. Comm enters asked why RE and EE should be favored over FF and nuclear

. Commenters noted that allowances for these fuels divert funds from creating sustainable systems.
Commenters urged EPA to favor wind power over natural gas in states that have cheap wind

res ources such as Nebraska and help build the transmission that will take that power across the country. Commenters also urged EPA to promote energy efficiency and demand side management in lieu of nuclear power while working with RTOs and other regional orga nizations to make and implement a practical plan to transition to a clean energy electric system.

Commenters stated that the Rule should disincentive dirty and dangerous energy sources like nuclear or natural gas to meet CO 2 goals, and instead rely on ener gy efficiency and renewable energy. Commenters urged EPA to ensure that the final Rule does not incentivize the construction of any new fossil fuel

- fired generation.

Comment 8: Commenters requested clarification regarding which measures and technologies they get to count and which they don't as they prepare their state plans

. Response 8: For the EPA’s response to this comment, see section V.A of the final rule preamble of the CPP.

The following are summaries of the specific public comments under this com ment:

Commenters would like clarification on what technologies fall under the rule and how the states can meet goals. Commenters cited the RIA attached to the rule which states that "for the purposes of this proposed rule, an affected EGU is any fossil fue l

- fired EGU that was in operation or had commenced construction as of January 8, 2014". Commenters stated this suggested the rule must limit its scope to fossil

- fuel

- fired generators and cannot consider the other types of generation (e.g. nuclear, hydro... ). However, commenters then cited the proposal, which states that "specifically, the EPA is proposing state

- specific rate

- based goals for CO2 emissions from the power sector, as well as guidelines for states to follow in developing plans..." Commenters sta ted that they are unaware of a definition of "power sector" that would selectively omit non

- fossil

- fuel

- fired generators. Commenters then stated that there is more confusion based on a quote from the TSD, which states "It is important to note that this "un der construction and at risk" nuclear capacity is also part of the inventory that the state can count towards compliance408 with its state goal." and also "Increasing the amount of nuclear capacity relative to the amount that would otherwise be available to o perate is a technically viable and economically efficient approach for reducing CO2 emissions from affected fossil

- fuel

- fired EGUs". Commenters asserted that this word choice would indicate that the EPA is not interested in a general reduction of CO2 emiss ions, or in reduction from a state's entire electric power sector (in contrast to the second RIA quote above), but only in measures that can displace CO2 that would otherwise be generated by existing generators going forward in a "business as usual" case. Commenters concluded by stating that if this meaning is the intent of the proposed rule, it should have been stated more clearly. Commenters also urged the EPA to clarify the compliance situation in this proposed rule. Commenters felt that states need to k now what they get to count, and what they don't, as they prepare their state plans.

Comment 9: Commenters argued that the definition of BSER seems to erroneously assume that: (1) any fossil EGU can be easily replaced by another lower carbon or zero carbo n generating capacity on a state

- by

- state basis without consideration to transmission and interstate markets, and (2) renewable energy and energy efficiency directly impact carbon emissions. Commenters argued that EPA's hypothesis that renewables and energ y efficiency will offset, MWh for MWh, fossil generation is an over simplification that does not hold true in the actual market.

Response 9: For the EPA’s response to this comment, see section V.B of the final rule preamble of the CPP.

Comment 10: Commenters stated, building blocks 2

- 4 can certainly be implemented and are certainly appropriate to affected units as they could involve engineering changes to the existing equipment and sources of fuel.

• Specifically building block 2

- This would not ne cessarily involve building a new EGU but rather modifying existing ones.

• Building block 3

- The operative words here are low carbon generation, which does not mean exclusively zero carbon generation. Also such affected EGU can employ carbon capture seques tration (CCA) technology since this block specifically refers to reducing emissions broadly and not just lower carbon fuels.

• Building block 4

- As for the criticism of "adequately demonstrated": In 2012, California avoided 12.5 percent of their electricit y demand through demand

- side energy efficiency programs. "Demand

- side management programs have existed across the globe since the 1970's. California utilities have used such programs (in tandem with a changing customer mix) to hold per

- capita energy consum ption nearly constant over the past 30 years". Demand Side Management (DSM) programs offer a variety of measures that can reduce energy consumption and consumer energy expenses. Electricity DSM strategies have the goal of maximizing end

- use efficiency to a void or postpone the construction of new409 generating plants (which should benefit suppliers and consumers!). DSM programs aim to achieve three broad objectives; energy conservation, energy efficiency and load management.

1. Energy conservation can reduce the overall consumption of electricity by reducing the need for heating, lighting, cooling, cooking energy and other functions.

2. Energy efficiency can encourage consumers to use energy more efficiently, and thus get more out of each unit of electricity produced

.
3. Load management allows generation companies to better manage the timing of their consumers' energy use, and thus help reduce the large discrepancy between on

- peak and off

- peak demand.

Response 10: The EPA thanks the commenters for their comments.