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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 economic 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 Heat Rate reduction opportunities for non-coal fossil fuel-fired EGUs ...................... 287

3.11 Potential emission reduction measures not used to set proposed goals....................... 315

3.12 Other .................................................................................................................................. 402
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3.5 ALTERNATIVE RE APPROACH

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.

Comment 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 valuable 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 costeffectiveness of these target generation levels are validated in IPM through a methodology based 

on the Alternative RE approach. Based on commenters feedback, the primary changes to the 

Alternative RE approach include removal of the technical potential limiter and updated cost and 

performance assumptions for the onshore wind and solar technologies. The final building block 3 

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 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. 

Commenters 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 renewable 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 adequately 

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 various 
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forms of renewable energy can effectively displace CO2 emissions from affected EGUs, and 

while EPA is right to include renewable energy generation 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, while 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 energy.

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

resources. Commenters 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 energy 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 TWh 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 Alternative RE Approach 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 each state. Commenters noted, however, that EPA's Alternative RE 

Approach 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 

determined 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 the 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 Alternative RE Approach, 
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but incorporate into the IPM more recent data evidencing continued acceleration of the 

deployment of these technologies. Commenters also urged EPA to modify the Alternative RE 

Approach 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 

potential in Nevada. Commenters noted that the proposed rule presents target values for state-byRE generation calculated for the final level (2029) and interim level (2024) for both the proposed 

and Alternative RE Approach, but noted that the Alternative RE Approach 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 hydropower.

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 appropriate gauge for future 

RE growth, and actual RE generation is not a direct corollary of technical potential. Additionally, 

commenters asked EPA to consider adding an indicator of the cost of intermittent resources in 

addition to the avoided cost metric that 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 

potential renewable electricity resources a state possesses and place these on a level playing field 

with each other which commenters 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 are 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 methodology incorporated for the Alternative 

RE Approach 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 resource, along with the associated market driven cost parameters, is 

fundamentally a more solid and prudent approach. Commenters noted that although the 

Alternative RE Approach 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 (inappropriate benchmark development rate that artificially limits 
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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. Commenters 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 state-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 aggregating 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 the 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 

Alternative RE Approach 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 situated; 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 installations; 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 existing 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 nonhydro 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 

resources in any given state.
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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 projections 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 rate 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 consideration by the 

EPA.

Commenters stated that these alternative RE targets are more closely aligned with existing RPS 

goals when ACPs are factored 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 state'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 than 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 

resources 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 transmission 
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system 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 than in-state 

electricity consumption. Commenters noted that this does not correlate well with existing state 

actions as most existing RPSs implement a renewable 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 energy 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 energy to outof-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 standards 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 also 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 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 recommended to adopt EPA's Alternative RE approach. Commenters stated that 

given the deficiencies in the proposed approach, they believe the Alternative RE Approach 

would be an improvement. Commenters stated, the Alternative RE Approach, 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 commenters 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 enable regulated utilities to meet RES mandates costeffectively by building or purchasing renewable resources in the most optimal location. 
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Commenters recommended that the off-taker of power should have the final say on where the 

credit should reside for compliance 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 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. 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 additional 

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-based 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-effective 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, respectively. 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. Modeling 
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projections remain an important aspect of the overall methodology in validating the technical 

feasibility and cost-effectiveness of the target generation level. The EPA has adopted a number 

of the proposed changes suggested by the commenters, 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 proposed Alternative RE Approach because potential alone is too 

slender a foundation for a state goal.

Commenters stated that the Alternative RE Approach underestimates the industry's potential and 

calculates only the impact of utility-scale renewable energy installations 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 Alternative RE Approach 

uses inaccurate and outdated assumptions about technology cost and performance; and bases 

2030 targets on 2012 installations, ignoring the way market adoption has accelerated due to 

declining costs. Commenters also disagreed with EPA's exclusion of offshore wind under the 

Alternative RE Approach. Commenters urged EPA to use a modified version of the proposed 

alternative renewable 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 recommended modifications to the 

Alternative RE Approach 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 realworld data on the cost of renewable energy technologies, as costs have 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) including 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 likely renewable energy 

growth.

Comment 7: 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. 

Response 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 EPA addresses 

considerations related to the technical feasibility and associated grid integration costs of 
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significant 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 exceeds 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 Alternative RE Approach 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 meaningful 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 with 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 

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 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 Central 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 target 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 Approach, South Dakota's obligation under the target is not capped, and instead, 

South Dakota's state-level 2030 generation target, excluding existing hydropower, is 19,156 

GWh of RE generation. Commenters stated this generation target would be incorporated into the 
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denominator of the state goal calculation in place of the RE generation levels quantified using 

EPA's proposed approach. Commenters including South Dakota's generation target based on the 

Alternative RE Approach 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 Alternative RE Approach. Commenters stated this would dramatically and 

unsustainably increase 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 percent if EPA 

were to adopt the Alternative RE Approach 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 Alternative RE Approach.

Commenters referenced page 8 of the Alternative RE Approach TSD, that states would not be 

required to achieve the absolute levels of target generation quantified under the Alternative RE 

Approach and incorporated into the denominator of the state goals. 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 states will meet their goals if EPA chooses the Alternative RE 

Approach 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 

Alternative RE Approach cannot provide substantial comments on how they might be impacted 

because of that.

Commenters stated that the expansion of RE is highly dependent on available 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, surrounding 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 States 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 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:
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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 

development 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.

Commenters 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. Commenters 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 alternative is too general to represent a 

realistic scenario for all states.

Comment10: 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 percent 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 these 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 based on artificial constraints such as the benchmark development 

rates described in the Alternative Proposal.

Comment 11: Commenters stated that the Alternative RE Approach for calculating RE goals 

does not reflect BSER.
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Response 11: For a detailed explanation regarding the inclusion of incremental RE to the BSER 

refer to section V of the preamble. Specifically, the final building block 3 methodology does not 

include the benchmark development rate that relied on NREL technical potential data. More 

broadly, 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 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 12: Commenters stated that EPA's methodology is flawed as it is based on

unsubstantiated assumptions regarding the rate at which states can develop renewable resources 

and the future costs of those technologies.

Response 12: 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. 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 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 Measures 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 13: 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 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 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 commenters 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 statebased results from an integrated national model.

Commenters strongly opposed the Alternative 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 developed significant amounts of renewable generation, like Oklahoma, 

because these states tend to be located in areas with renewable resources and the "potentialbased" analysis employed by EPA has little connection to practically or economically 

developable outcomes. Thus, commenters stated that the Alternative 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 alternative 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 states.

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. Commenters 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 exceeding 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 would 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 increases 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, that 
15

under the Alternative RE Approach, South Dakota's obligation under the target is not capped and 

instead, South Dakota's state-level 2030 generation target, excluding existing hydropower, is 

19,156 GWh of RE generation. Commenters stated that including South Dakota's generation 

target based on the Alternative RE Approach causes South Dakota's final rate-based CO2 

emission performance goal to decrease from 741 pounds CO2/MWh under EPA's proposed 

approach to 185 pounds CO2/MWh under the Alternative RE Approach. Commenters stated that 

the percent reduction in South Dakota's state emission rate -- a state with one of the lowest CO2 

emissions rate in the nation -- that the proposed rule requires would increase from 35% to 84% if 

the EPA were to adopt the Alternative RE Approach for quantifying RE for BSER. Commenters 

stated that applying the Alternative RE Approach to EPA's calculation of state-wide emission 

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 an 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 undertake its own proceeding to consider the factors listed above 

and develop a target that is achievable.

Comment 14: 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 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 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 commenters concerns, the final 

methodology provides a greater transitional 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 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'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 renewable 

energy incrementally each year, allowing for a transition to a more diverse energy portfolio.

Comment 15: 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. 
16

Response 15: 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 data, 

assumptions, methodology, and outputs associated with relevant IPM projections are available 

on the EPA’s power sector modeling website, 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 the 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, assumptions, 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 original 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 16: Commenters stated that neither of the alternative RE approach calculations 

provide a reasonable method to determine achievable RE generation targets for states. 

Response 16: 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 does not include the technical potential limiter referenced by the 

commenters. 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.

The following are summaries of the specific public comments under this comment:
17

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 arbitrarily 

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. Commenters stated EPA would not consider factors that 

may lead some states to develop specific renewable energy technologies more than others. 

Commenters 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. Commenters 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 potential 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 resources 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 compliance 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 allowing 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 17: Commenters stated that they prefer the Proposed RE Approach over the 

Alternative RE Approach.

Response 17: 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. Finally, 

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. Commenters 

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. 

Commenters 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 noted that for some states, EPA's Alternative RE Approach 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 its 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 targets 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 commenters and other 

stakeholders have proposed elsewhere.

Commenters said that due 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 initial 

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 18: Commenters opposed the application of any other alternative approaches for 

Building Block 3, including any methodology based 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 emission reductions requirements for the Navajo Nation.
19

Response 18: 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. Finally, 

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 for CPP Final Rule and in the GHG Mitigation

Measures TSD.

Comment 19: 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 19: 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 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, commenters 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 specific 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 individual 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 Alternative 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 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 

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

Commenters stated that the benchmark generation calculation 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 renewable energy that each state can 

achieve by 2030. Therefore, commenters 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 incorporate 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 source 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 

generation 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 current 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, commenters stated that the portion of 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 21: 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. 

Response 21: 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 statespecific 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 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 following 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 highest 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, 

commenters 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, commenters stated it is difficult to argue that all 16 

states should be used for wind and solar, 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 achievable 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 the 
22

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 top 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 increase) 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 that 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 potential 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 such 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 Alternative 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, commenters added that EPA has 

provided no demonstration of IPM's accuracy and reliability for 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 enforceable 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 

wind 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 integrating 
23

large amounts of intermittent wind energy under this approach by evaluating the development 

rate on a regional, not national, basis.

Commenters 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 stated 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 states 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.

Commenters 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 agricultural 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 achieving 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 with 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/opposition 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 that 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 separating 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 technology? Commenters noted that because the Agency uses a generic and unrealistic 

benchmark rate in its calculations, Indiana's renewable energy target under the Alternative RE 

Approach is 20 percent of the state's electricity generation by 2030 which is nearly 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 states 

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 states is replicable, sustainable 

and achievable for all states. Commenters 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. Commenters 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 states 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. Commenters noted that this approach would provide a better estimate of 

what may be achievable 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 that to 

the extent EPA retains its Alternative RE Approach 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 flexibility 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 22: 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 22: 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 that 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, but 

noted that EPA has weakened its approach by relying on outdated and inaccurate data, such as 

EIA AEO 2013. Commenters 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 within 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 the 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 solar projects known to be under construction through 2016, show double the 

amount of renewable energy potential than EPA's analysis.

Commenters noted 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 47 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 the 47 states 

analyzed by EPA is 9% higher than the same 8 months in 2013. Lastly, commenters 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 months 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 represent 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. Commenters noted the large impact of taller wind 

turbines as, for example, Tennessee's estimated wind energy resources are approximately eightythree times greater (over 25,000 megawatts of potential) when conducting a resource assessment 

using a 140-meter tower, 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 renewable 

technologies. Commenters stated that the resulting national target for renewable generation 
26

nearly doubles from EPA's approaches, growing from 520-530 TWh to 930 TWh, which the 

commenters 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 also 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 each 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. Lastly, commenters 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 resources.

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 data.

Comment 23: Commenters recommended that EPA update the cost and performance data used 

in IPM modeling to support the Alternative RE Approach. 

Response 23: 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 costs 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 state 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 installed 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 "Power 
27

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. Commenters 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 NREL, 

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 the 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 solar and that the benchmark development rate also generally 

results in low capacity target levels.

Comment 24: 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 24: 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 noted that EPA's option for states to set renewable energy targets based on each 

state's technical renewable 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 which influence 
28

the actual deployment of RE generation. Commenters stated that states with similar technical 

potential may have vastly different achievable potential and that states should have more 

flexibility in identifying potential.

Comment 25: Commenters urged EPA to utilize a determination of technically potential 

renewables in a similar manner to the National Renewable Energy Laboratory (NREL) estimates. 

Response 25: 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 

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 26: 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 constraint on development.

Response 26: 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 27: Commenters stated that EPA should exclude the technical potential benchmark 

from the Alternative RE Approach and rely solely on the IPM model results. 

Response 27: 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 more 
29

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 results 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, commenters suggested that EPA consider implementing constraints 

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, providing 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 precedent is therefore 

to rely solely on the IPM model for setting the renewable targets in each state under the 

Alternative RE Approach. Commenters proposed a second alternative which would be to use the 

demonstrated recent growth rates of renewable energy technology as the basis for the benchmark 

element of the approach rather than absolute 2012 development rates. A third option offered by 

the commenters is that EPA could increase the technical cap to account for technological 

improvements and cost reductions that 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. Commenters stated that not only 

does the IPM model contain the same technical 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 realworld limiting factors such as economic growth and grid constraints and therefore, EPA should 

not rely on NREL's technical potential for setting state goals. Commenters stated that, 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. 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 setting 
30

state goals. Commenters noted that there is precedent to rely solely on the IPM model for setting 

renewable targets in each state, as multiple other policies solely utilize the IPM model to 

calculate targets.

Comment 28: Commenters stated that instead of using the benchmark rate, EPA should 

implement constraints that more closely simulate real-world grid operations. 

Response 28: 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 wind) 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 renewables, 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 29: Commenters recommended that EPA drop the entire technical potential 

calculation and simply use the market potential to establish RE targets by state. 

Response 29: 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 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 the 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 analysis 
31

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. Commenters 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 summaries 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 justifiable 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 31: 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 31: 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:
32

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. Commenters noted that experience shows that such a cap is not binding 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 that drive and limit renewable energy 

development. In the alternative, commenters 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 technology 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. Commenters 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, commenters 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 continuous 

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 commenters 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 justify 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 

potential 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 disproportionately 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 and 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 Renewable 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 associated 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 32: Commenters believed that EPA should include a "floor" for renewable energy in 

its Alternative RE Approach methodology. 

Response 32: 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 are assigned to all affected sources within that 

interconnection. 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, increased 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 growth 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 states 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 renewable resources as reported by the U.S. 

Energy Information Administration's Annual Energy Outlook 2014.

Comment 33: Commenters suggested that EPA establish a "ceiling" in its Alternative RE 

Approach methodology.

Response 33: 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 are assigned to all affected sources within that 

interconnection. 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 Alternative RE Approach more realistically bounds the 

renewable energy analysis, however, further ceiling 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). Commenters 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 

perspective. 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 ceiling 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 34: Commenters believed that EPA should modify the alternative RE approach to 

provide credits for states that have adopted and implemented updated building code policies.

Response 34: 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 states 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 the 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 savings could be calculated to provide 

credits towards South Carolina's emission reductions.

Comment 35: Commenters stated the cost and performance assumptions in the Alternative RE 

Approach inaccurately represent renewable energy technologies. 

Response 35: 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 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:
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 

amount 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 resource. 

Commenters stated that the Alternative 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, commenters stated that the 

underlying base case cost data so significantly 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 case are $3.364 per W, compared to an average of $1.7 to $1.8 per W observed already 

in 2014. Furthermore, commenters 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 capacity 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 provide EPA with additional information to more accurately estimate technology cost 

and performance.

Comment 36: Commenters stated that EPA's Alternative RE Approach relies on unsubstantiated 

assumptions about the growth and future cost of renewable technologies. 
36

Response 36: 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 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 relies on unsubstantiated assumptions 

about the growth and future cost of renewable technologies. Commenters stated that EPA's 

Alternative RE Approach focuses on technical potential despite acknowledging the limits of this 

approach. Commenters stated technical potential is divorced from reasonably achievable 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 effort 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 firming 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, policies 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 factors 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.). Commenters 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 

Dakota'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.

Commenters 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 genuine 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 

conduct a more robust analysis that considers technology- and region-specific trends, policies 

and development constraints before finalizing state goals for renewable energy.
37

Comment 37b: 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 37: 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:

Commenters 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 figures 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 capacity value of solar photovoltaic from 20 to 16 

percent. Finally, commenters 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. 

Commenters 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 EPA'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 38: Commenters stated building block 3 should address transmission costs.

Response 38: 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 if EPA finalizes the Alternative RE Approach, it should ensure that final 

assessment of building block 3 consider transmission costs and noted that significant additions of 
38

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 located 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 amount 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. Commenters 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 approximately 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 remain 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 utilities 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 39: Commenters urged that that capital cost adders implemented in EPA's analysis be 

updated to reflect real-world conditions in the solar PV and wind industries. 

Response 39: 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 www.epa.gov/powersectormodeling 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 RE 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 GW for onshore wind; in reality, the capacity-weighted average 

capital cost of wind projects installed in the U.S. dropped by 10 percent in 2012, despite 
39

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 utilityscale 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 this 

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 volume 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 that 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 expanding 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 unreasonable amount. Commenters stated that the EPA also applied

unrealistically high short-term capital cost adders to renewable and conventional generation 

technologies if the new capacity developed in a specific year exceeds a certain upper bound. 

Commenters believed that the assumptions made by the EPA are not supported by actual 

experience or credible 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 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 generation 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. The EPA addresses 
40

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 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 independent 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, it 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 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 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 reduction 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 solar] 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 policies 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 justify 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 renewable 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 achievable 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 energy 

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 strongly 

influenced by tax credits and subsidies, federal production tax credit and investment tax credit 
41

have already expired or are scheduled to expire before the states file compliance plans. 

Commenters stated that it is not reasonable to expect 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 

Alternative 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 metric 

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 renewables 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. Assuming 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 based 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 has 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. Commenters stated EPA must provide an 

adequate justification for its usage 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 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 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 that 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 for 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 threshold 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 42: 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 42: 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 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 generation 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 the 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 let the 

model meet the constraint at the lowest cost. 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 43: 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 43: 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 metric 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. Commenters 

constrained variable renewable generation at 30% of generation based on the results of several 

studies, which the commenters expected to be revised upwards by EPA as a result of EPA 

examining the latest available research. Commenters modeled two scenarios - 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 scenario, 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 

distributed solar is accounted for - between 65% and 86% higher than both of EPA's targetsetting 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/tonne 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 within 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.

Comment 44: Commenters cited issues with the NREL data used by EPA to calculate resource 

potentials under the Alternative RE Approach.

Response 44: The resources and data provided in this comment were valuable in finalizing the 

building block 3 methodology. Due to commenters concerns, the technical potential benchmark 

has been eliminated in the EPA’s final methodology. 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 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 conclusions 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. However, 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 alternative. Commenters 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, commenters 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 NREL 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 of areas outside of Department of Defense installations, such as military air navigation 
45

routes, air traffic control areas, military training routes, special-use air space, radar, and other 

potentially affected military operations. Commenters noted that North 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 wind 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 

achievable 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 Areas, 

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 the 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 exclusions 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, 

reliability, 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 power 
46

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 technology, 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 approximately 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 commenters 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 technical 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 

modeling 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-production 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 energy.

Comment 45: Commenters expressed concerns related to using a technical potential metric. 

Response 45: The resources and data provided in this comment were valuable in finalizing the 

building block 3 methodology. Due to commenters 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 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 despite 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 

development: 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 modeling approaches from other sources that use 

similar assumptions. Commenters supported the National Resource Defense Council's analysis of 

the EPA's Alternative RE Approach using an updated version of the IPM model, and stated this

addresses many of their concerns. 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 

Approach. 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 renewable potential and 

that it does not capture the economic potential for deploying renewables at higher levels to costeffectively achieve deeper emission reductions. 

Comment 46: Commenters had concerns about how hydroelectric generation was calculated in 

the Alternative RE Approach. 

Response 46: 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 capacity. 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 Alternative 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 technical 

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 potential 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 hydroelectric 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 makes 
48

little sense, as there is no reason a state should be held to either potential new hydroelectric 

generation or existing generation. Rather, commenters suggested these values should be added 

together to get an estimate of total potential hydroelectric generation. Or, commenters 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 report 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 hydropower) 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 

hydroelectric 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 set 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 state from the NREL report as the basis for 

calculating each state's technically feasible, cost effective generation from hydropower. 

Alternatively, commenters stated, if EPA decides to include generation from existing 

hydroelectric facilities, it should include existing hydroelectric generation both in its calculation 

of generation using IPM, as proposed, and in its calculation of benchmark hydroelectric 

generation. However, commenters stated, generation from existing hydroelectric facilities should 

be included 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 commenters 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, commenters 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 

hydroelectric potential in these states, which is not considered in any reports cited by EPA.
49

Comment 47: Commenters expressed concern about the interaction between EPA's Alternative 

RE Approach under Building Block 3 and the remaining Building Blocks. 

Response 47: 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 premise 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. electricity 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 cost-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 additional 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 Alternative RE Approach used the carbon price metric rather 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. Commenters 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 importance of incorporating renewable 

energy generation based on the actual potential for each state, and the approach described in the 

technical support documentation "Alternative Renewable Energy Approach" may be closer to 

representing state realities as it 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 regional dispatch area and the use of an estimated incremental cost of renewables. 

 

1 http://www.nrel.gov/docs/fy12osti/52409-1.pdf
50

Commenters stated that EPA did not provide information regarding the impact on the Alternative 

RE Approach to the emission performance requirements for Florida, specifically whether the 

adoption of the Alternative RE Approach would affect the other Building Blocks.

Comment 48: Commenters stated the alternative RE proposal would have a significant impact 

on Minnesota's final target. 

Response 48: 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 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 rate achievable by a new NGCC, but little 

else.

Comment 49: 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 49: 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 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. Commenters noted that this is a 519 percent increase in RE generation compared to 
51

Indiana's demonstrated performance of 3,546 GWh in 2012. Commenters stated that while 

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 

that 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 additionally 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 consumers than necessary.

Comment 50: Commenters provided a list of questions about 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 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 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 reduce power 

sector CO2." 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?
52

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

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 methodology 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 that 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 Central 

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 from 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 alternative 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 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 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 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 agency 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 energy 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 conditions 
54

across potential deployment sites) that complicate identifying a technically feasible and costeffective 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).

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

Commenters noted that EPA stated in the Alternative RE Approach 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, 

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. 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. Commenters stated 

that the SolarDS model 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 in 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, commenters 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. Commenters 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 industry 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 

instead 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 parties 
55

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. 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 the United States, including 

demonstrated RE technologies for which there is clear evidence of technical feasibility and costeffectiveness (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 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 

distributed 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 generation resources and 

allow these credits to count towards emission reductions in some manner in addition to utilityscale renewable energy installations. Commenters also noted that South Carolina has tremendous 

offshore wind potential and that numerous studies 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 and 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 

could 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 2023(Navigant Research, Global Distributed Generation Deployment 

Forecast, (September 2014)) while offshore wind technologies are also rapidly improving worldwide. Commenters noted that IPM does not currently have the capability to calculate economic 

constraints for distributed solar and other customer resources, and does not capture potential 

progress 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 technical 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 technology 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, 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.

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

Commenters stated that the Alternative RE Approach utilizes existing models 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.

Commenters noted that while a state may include electricity 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 pursuing. Commenters 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 establishing 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 Alternative 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 under 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 commenters voiced support for excluding biomass-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 commenters

focused on the inconsistent treatment of the technical potential of biomass under the Alternative 

RE Approach as compared 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 states' targets. Commenters stated that EPA should continue to exclude 
57

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 incorporated.

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, and 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 costeffective 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 regions. 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 because 

available supplies of low-carbon biomass are likely to be very limited and the EPA 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 suggested EPA fix IPM so it can model cost-effective hydropower 

potential and use the results to increase the assumed hydropower potential based on regionspecific 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 methodology 
58

chosen in the technical and economic potential approach, results in an effective 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 hydropower 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 additional 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 proposed 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 potential 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 

appropriate 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 technologies 

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 remove existing hydroelectricity from the goal-setting 

calculation. Commenters noted that including existing hydroelectricity in this approach's goalsetting 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 from 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 BSER. 
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 additional 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 include 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.

Commenters 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 "Alternative 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 potential 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 feasibility 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 not 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. This 
60

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 energy 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 potential 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 residential 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 the 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 technically 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 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 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 based 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 of 
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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.

Commenters 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 believed that the 

technical potential 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 

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 believed that with the correct solar data inputs, the IPM model provides a realistic 

projection of solar energy potential at the state 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 in each state under the Alternative RE Approach. 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 transmission 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 set 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 

demonstrated RE technologies for which there is clear evidence of technical feasibility and costeffectiveness (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 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 United 
62

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. waters 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 recommended 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 comments 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 are 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 statespecific 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 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 correctly 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, operating 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 model (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 from 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 Alternative 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 utilization 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 generation 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 from 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 relative 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 renewable 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 statespecific 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 performance 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 
64

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 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-ofstate renewables for compliance. Commenters stated that establishing state Building Block 3 

targets by apportioning regional 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 the 

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 based 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 constraints. 

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 should 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 costs 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 accurately reflecting today's costs is a 
65

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.

Commenters stated that to the extent feasible in the technical and economic potential modeling, 

EPA should expect that grid changes will enable even more 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 the 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 

Renewable 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 curtailment 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 Alternative RE Approach and rely solely on the 

Integrated Planning Model (IPM) model 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 recommended 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 statespecific 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 performance 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 costs 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 generation 

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, commenters stated EPA should design a methodology that does not apply a 

development rate constraint to the potential renewable energy available as proposed 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 this 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 using 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 more 

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 better 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 to 
67

compare 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 included with market costs and 

benefits in assessing the options for particular levels of carbon prices in US$/tCO2 and US$/tCeq. (as affected by mitigation policies) and when using social discount rates instead of private 

ones. Commenters stated this 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.

Response 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 potential, 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 lacks the time to complete a more thorough 

technical potential analysis, and commenters cannot, in good conscience, recommend an 

approach resulting in the Washington targets produced by EPA's analysis. Commenters stated the 

2012 existing renewable energy (excluding 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 better 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 that the analysis underlying the Alternative RE Approach 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 and 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-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 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 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 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 are 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 renewable 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 information.

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 entities 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 potentialbased approach requires enormous amounts 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 

states 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. Commenters 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 expressed 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 that EPA set the target for the renewable technical and economic 

potential approach as an energy target expressed in MWh. Commenters stated targets based on 

potential 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 instate generation can fluctuate wildly in hydropower dominant states 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 over 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 preamble 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 suggested 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 certain 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 modeling 

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 this 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 economic 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 system 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 costeffectiveness of the target generation level. 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:
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 relates 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 Hawaii 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 

commenters, is more indicative of the market potential of wind and solar in Alaska and Hawaii. 

Commenters noted 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 

stated 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 target 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: Commenters 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.

Response 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 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 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 Arizona 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, reduce 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 Approach is 

problematic. 

Response 3: The EPA has not expressed a building block 3 requirement associated with Hawaii. 

For additional detail on this 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 that for Hawaii and Alaska, the Alternative RE Approach 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 Approach 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 account 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 the "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, commenters believed that the 

application of EPA's approach for estimating potential RE growth is insufficiently justified and 

did not recommend the use of this Alternative RE Approach for quantifying RE generation as 
73

BSER for Hawaii. Commenters stated that the RE estimates Hawaii, whether fixed or with 

growth (under the Alternative 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 the "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 "GHG 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 not referenced in the text, while it appears to conflict with the 8% value, the 9% value may 

refer to something else. Commenters also noted that the "Alternative RE Approach" TSD 

references the "GHG Abatement Measures" TSD when noting the annual growth factor 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 Alternative 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 states 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

Response 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 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 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 reduction 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, in 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 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 

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 disagreed with EPA's assessment of Kansas' renewable energy generation when 

developing state goals under the Alternative 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, commenters 

conservatively estimated that the required cost of transmission construction to move such 
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amounts of wind energy (in Kansas alone) is $6.5 billion, which exceeds the entire forecasted 

reliability-based construction estimates of the entire SPP between 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 the proposed rule 

would make the Alternative RE Approach 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 result 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 because 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 GIS-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 constraints 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 scrutiny for 

environmental, cultural or social reasons. For example, commenters 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 limited 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 constraints 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 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 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 potential. 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 renewable energy sources--a reduction compared 

to current levels---to maintain a level of performance similar to other high performing renewable

energy states. Specifically, commenters noted that EPA suggests that Louisiana could reduce its 

total renewable energy generation from its 2012 level of 3,110 gigawatt-hours to 2,503 gigawatthours 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. Commenters 

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 deference 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 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:
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 without 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 Minnesota 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 receive 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 of 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 been 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, 

approval 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 areas 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 surrounding 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 States. 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 agencies 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 sense.

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 assessment 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 stated 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, 

infrastructure 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 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 New Hampshire's renewable resource potential was specifically 

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 

States. Commenters stated they do not support any efforts to use the CPP state renewable 
79

analysis to redefine RPS requirements, or that would affect the existing generation unit 

qualification requirements for each state's renewable standards.

Comment 11: Commenters 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 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 while RE should 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 rather 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 economic 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 New 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 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. 
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 striking 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 resources-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 

generation 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 EPA'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 stated 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 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 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 its 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 3 
81

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 believed the targets established for South Carolina, a reduction of 772 lbs/MWh or 

51% of carbon emissions, are achievable through new clean and renewable energy and energy 

efficiency investments. However, 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. 

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 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 inclusion 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, costeffective, and adequately demonstrated 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 modifications, 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 modifications. 

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 numerous 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 energy's contribution for state 

targets. However, 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 following 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 performance 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 renewables 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 transmission 

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 utilized 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 tracking 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 regional 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 compliance, 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 of 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 the 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 markets would better reflect the realities of the interconnected electricity grid and how 
83

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 generation 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 opinion 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 stated 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 Agency 

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 more 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 stateonly or regional approach. 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 Renewable 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 analysis 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 the 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 approaches to setting state renewable energy targets is unclear as to exactly 
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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 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 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 said, 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 fundamentally 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 state.

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 region.

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 for 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, commenters stated it may or may not include existing generation (beyond 

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, 
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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 recommendations 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 jurisdiction, 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 blocks 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. 

Commenters 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. Commenters 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 facilitated 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 EPA's proposed and Alternative RE Approach 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 

arbitrary 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. Commenters 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, which 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. However, 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 meeting that same target. 

Commenters also noted that EPA's alternate approach to determine state renewable energy 
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targets is also flawed and using a regional approach to apportion the renewable energy 

generation will not address these flaws.

Commenters stated 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 operators 

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 concerned 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 are 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 inadequately accounting 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 targets 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 made 
87

clear that the increased penetration 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-state 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 methodology used in the Alternative RE Approach is 

flawed, any state-by-state allocation of targets derived from the Alternative RE Approach is also 

flawed and that EPA should refrain from conflating renewable energy data from different states 

altogether.

Comment 3: Commenters stated the 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 

from another jurisdiction without a multi-state compliance plan. See sections 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:

Commenters stated concerns regarding the regional nature of electricity would remain an issue 

under the NODA approach. Commenters 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. Commenters stated that a state that 

is a net importer of RE will benefit from a regional approach that allows it to take credit for RE 

built in another state, but serves load within the importer state. In contrast, commenters stated, a 

net RE exporting state has little to no incentive to allow renewables produced in the exporting 

state to be counted elsewhere. Commenters stated while the regionalized approach attempts to 

recognize the interstate nature of electricity, individual state goals create complications. 
88

Commenters stated individual 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. See 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. Commenters observed that a 

regional reapportionment of appropriately derived renewable generation targets may reduce 

disparities between state targets. Specifically, commenters stated that given that the electricity 

produced by renewable resources will be utilized 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 energy 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 the extent 

that a state lacking substantial in-state renewable resource potential is required to rely on out-ofstate renewable generation to comply with a regionalized target, such compliance will be subject 

to siting, permitting, and other regulatory actions 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 should 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 sections 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), a 
89

carefully designed Regionalized Approach may alleviate stakeholder concerns that state targets 

do not match available compliance mechanisms, as identified 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 credits. 

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, commenters noted that a 

regionalized approach would better align RE targets with the proposal 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 section V of the final rule preamble 

of the CPP. The EPA has provided clear guidance in section VIII of the final 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 flexibility 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 technical 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 are 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 resources 

(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.

Commenters 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 Standard ("RES").

Comment 7: Commenters expressed support for a regional to RE goal setting.
90

Response 7: The EPA agrees with this comment. See 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 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 achievable 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 energy 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 purposes 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 

building 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 methodologies. 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 this 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 potential 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 technically 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 commenters 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 of 
91

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 stated 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 regional 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 rightly 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 states may differ in important ways, including in their mix of existing 

EGUs and policy 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 consideration to interstate opportunities in the goalsetting 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 allows 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 

among 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 through 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 generating 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 Southeast 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 

into 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 rule based on the regionalized 

version of its Alternative Renewable Energy Approach set forth in the NODA, subject to the 

proposed modifications.
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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 approach coupled with expressing building block 3 in terms of

incremental RE corrects for the mismatch described by the commenter. Refer to section VA 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 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 allocated 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 renewables 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 variable 

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 using 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 sufficient 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 rely 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 VA. 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. Commenters 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. Commenters believed that 

this framework best represents states' abilities to accommodate a share of the increase in the 

region's RE and gives incentives to states to pursue policies that encourage the use of RE. 

Commenters noted that this framework also most closely matches the way states will utilize 

renewable energy to demonstrate compliance 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 building block 3 generation levels. See section VA. 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 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 generation 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 

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 for the most part, they think that grouping of states reflects the manner in 

which they are currently involved in interstate renewable exchanges and are likely to be so in the 

future. However, commenters 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.
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Comment 12: Commenters 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 resources are grouped with all Eastern Interconnection affected EGUs. See 

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 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 the 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 essential 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 count 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 

deliverability, the BSER should reflect the reality of those existing RPS provisions. 

Moreover, commenters 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 interconnection 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 requirements 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 VA 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:
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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 applied 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 least 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 

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 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 there 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 PJM interconnection queues for 

proposed wind projects in North Carolina.

Comment 15: Commenters stated Kentucky's load/generation and renewable resources should 

be grouped with EPA's North Central region.

Response 15: The building block 3 regions are the interconnections; consequently, all Eastern 

Interconnection resources are grouped with all Eastern Interconnection affected EGUs. See 

sections V.A and V.E of the final rule preamble of the CPP for 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 the 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.
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Comment 16: 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: The building block 3 methodology relies on the ability of affected EGUs to 

procure incremental RE within the interconnection. Refer to 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 the adequately demonstrated ability of Southeastern utilities to import wind 

energy generation 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

Central) 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 characteristics 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 

the 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 achieving 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 

EIPC 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 Base 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 connected to these lines and would not have 

another path for delivery.
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Comment 17: Commenters stated the ERCOT IPM region does not include wind resources in 

the Texas Panhandle.

Response 17: The RE resource potential in IPM is described 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 suggested 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 significant 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: Commenters stated there are inaccuracies in the IPM assumptions table.

Response 18: 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 comment:

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 increased 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 current 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 unable 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 those 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: Commenters suggested the EPA base RE targets on technical potential.
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Response 19: The final building block 3 methodology is premised on historical deployment of 

RE capacity rather than modeling projections. Refer to 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 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 throttled by an avoided cost threshold, consistent with utility planning.

Comment 20: Commenters expressed concern that the alternative approach would result in 

unrealistic rate targets.

Response 20: The final building block 3 methodology is premised on historical deployment of 

RE capacity rather than modeling projections. Refer to 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 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 levels 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 provided 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, commenters 

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: 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: The EPA adopted a regional approach to building block 3 as it was most 

consistent with the BSER. See sections VA 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 

based 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 and 

economic potential approach, and provided suggestions for strategies to either fix or compensate 
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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 commenters would recommend using the "regional potential" approach outlined in the 

NODA. Specifically, commenters 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, commenters stated, 

this approach is more consistent in terms of using the data that provides the foundation for the 

assigned targets. Also, commenters 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 develop resources in other states, 

commenters 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, notwithstanding 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 outof-state renewables is not appropriate. Commenters stated that they prefer a method that sets instate RE goals based on in-state technical and economic potential; however, should EPA 

determine that such a method cannot be implemented, then the commenters strongly prefer an 

approach based on regionalized technical and economic potential over the proposed RPS 

approach. 

Comment 22: Commenters stated the EPA should credit excess RE based on the regional steam 

fossil emissions rate.

Response 22: 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 demonstrate 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 emissions savings that would be 

produced by adding renewable energy, given how renewable resources displace fossil generation 

resources throughout the region due to the interconnected nature of the power system. 
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Commenters stated that if all regional steam fossil generation is exhausted, renewable generation 

should be credited at the region's natural gas combined cycle (NGCC) emissions rate.

Comment 23: 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 23: The EPA agrees with this comment. Affected EGUs in Indian Country are subject 

to the same interconnection-level requirements as other affected EGUs. See 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 emissionsweighted share of the renewable energy available in the transmission or market region. 

Commenters stated that there is no justification for adopting a unique Alternative RE Approach 

which assigns a lower renewable generation target to these facilities. Commenters stated that for 

the power plants in U.S. territories, 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 alternative 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.

Comment 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 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 stated that this approach 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, 
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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 starting 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 generation, 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 require 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 are, at a 

minimum, as stringent as its RPS obligations.

Comment 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 Alternative RE Approach 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 by 

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 be under construction through 2016. Commenters stated that to calculate RE targets for 

2030, employed a four-step approach:

1. First, commenters 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 growth 

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 
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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, commenters 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 deploying 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 deploying renewable energy at or 

above the national benchmark, commenters 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 per 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 account for full compliance with mandatory state RES laws, commenters 

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 

renewable 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 states 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 the 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 approach'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 in 

their state compliance plans, they recommend that the EPA consider including a contribution 

from offshore wind as a potential BSER option over time.
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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 electricity 

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 Clean 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 affordable 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 increase, 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 Concerned 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 reasonable.

Comment 3: Commenters suggest an approach that considers regional differences in RE 

technology 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:

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 
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energy 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 2012), including generation 

from distributed solar PV, which the EPA did not include. 

To calculate 2030 state RE targets under this approach, commenters divided 2013 renewable 

generation by NREL's estimated resource technical potential for the following technologies: 

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 average 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 each 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, using 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 each 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 

electricity 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 baseline 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 increase over both EPA's proposed and 

Alternative RE Approach. 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 renewable potential and low electricity sales.
105

3.6 INTERACTION OF BUILDING 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 

comments.

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 blocks, 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 final 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 encompassing 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 all 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 the 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 interaction will be feasible. Both building 

blocks are conservative, in the sense that they do not require either to be utilized to the maximum 
106

extent possible. The RE goals for building block three are set based on a middle range of 

expected levels of development, while the NGCC capacity factor goals are based on a capacity 

factor that is less than full load and is 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 Preamble 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 ancillary 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 issuance 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 mechanism, 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 

discussed 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 based 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 

among 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 interactions 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 effectiveness 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. Commenters 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 proposal 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 complementary 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 is 

already at high levels and state that there are synergies among the building blocks that can 

increase their 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 technologies, 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 complementary 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 system 

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 System 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 contended that these states are not 

anomalies; seven other states supplied at least 12 percent of their total annual generation from 
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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 Building 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: EPA 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:

Commenters 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 existing 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 most 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 Block 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 the 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 operating 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.
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Commenters stated that coal based power production 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 baseload power mandated 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 heat 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 methodology 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 they 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 actuality 

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 dispatch 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 frequently 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 SO2 emissions increases that will 

result from operating 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. Commenters 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 that 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 swing 

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 coal 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 CO2 emissions) by 4 to 8 percent, depending on boiler design and coal rank. 
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Commenters stated that the changes in coal-fired EGU capacity factor required under Building 

Block 2 could very well 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 

rates 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 tandem 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 from 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. Commenters 

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 impacts their heat rate. Commenters stated that a shift to lessdispatchable, 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 

throttling 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 run at less than optimal capacity.

Commenters stated that coal-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% is 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, commenters 

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 factors in coal plants can increase heat rate. Commenters stated that if 
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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.

Commenters 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 will, 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 and 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 for 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 coalfired 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 harder 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 due 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 generation 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 efficient 
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manner. Commenters noted 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 plants 

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 plants 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 plants 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 stated 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 that 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 targets 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 the 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 facility 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 blocks on each other. 
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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 steam 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 that 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 there 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 the 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.
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Commenters questioned the reasonableness of investing in heat rate improvements 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) represents 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 are 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 stated the proposed CPP cost 

analysis should recognize that any assumed economic benefit from BB1 efficiency projects will 

be compromised by BB2. 

Commenters noted that Block 1 involves reducing the carbon intensity of generation at 

individual affected EGUs through 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 will 

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 ERCOT 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 coupled 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.
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Commenters stated that building 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 needed 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 commenters 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). The 

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 appeared 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 improvements 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 captured 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 Block 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 stated that coal units would be forced to adjust output to follow 

load changes, reducing their efficiency.
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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 explains 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 for 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 the 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 the 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 and 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 reduction 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 achieved 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.
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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. 

Plants 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 Power 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 efficient 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 upgrades, 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 and 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 balance 

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 coal 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 intermittent 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 stated 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 

deployment of renewables on the efficiency of the existing fleet.
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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 inappropriately 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 complying 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 factor 

of coal plants, as a result of Building Blocks 2, 3 and 4. Commenters stated that the heat rate 

becomes more unfavorable as the unit operates at lower loads. Commenters cited data that 

supported claim. 

Commenters stated that EPA overlooked the negative 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 generation 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 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 goal. 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 state, as well as nationally. 
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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 average 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 improvement 

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 displacement or reduced use of certain coal resources. Commenters 

stated that such 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 reduces 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 independently 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, The 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 required 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 constraints 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.

Commenters 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 fossil 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 other, 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 variable 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, 
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increased cycling, and increased 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 achieve 

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 overestimate 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 to 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 

units 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 achieving 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. Commenters 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 envisioned. 

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 profile, 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 emissions 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 proposed 

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.
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Commenters suggested that the EPA should 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 

knowing 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 overall, 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 noted 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. Therefore, 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 capacity 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 are 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 factor 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, 

effectively 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 stated 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 associated 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 noted 
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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 generation 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 direct 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 those 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 the 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 the 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 integrated 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 efficiency) is technically feasible, economically practicable and 

consistent with the APA standards, and the assumptions for each separate analysis are not 
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reconciled. Commenters explained that while this may make sense from the point of view of 

passing legal muster 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 following 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 for 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 existing 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, commenters 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 for 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 must 

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: Commenters 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 that 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 on 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 compliance 

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 

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 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 stated 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 displaces 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 lower 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 states 
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with significant 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 renewable 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 generation 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 that 

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 renewables 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 increase 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 work 

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 renewable 
126

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 goal. 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 state, as well as nationally.

As 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 BSER 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 has 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 is 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-fuelbased dispatchable resources and usually provide these services. Commenters stated 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 utilization 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 generation 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 ability to 

integrate additional renewables into the grid unless other resources are added. Commenters 
127

concluded that these interrelationships undermine EPA's assertion that the desired level of redispatch 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 generation 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 increase 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 goals 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 capacity 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.

Commenters 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 wind 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 are 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 following are summaries of the specific public comments under this comment:
128

Commenters stated that one outstanding question is whether states can build new natural gasfired power plants to meet their carbon-reduction targets under the Clean Power Plan. 

Commenters 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 average 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." 

Commenters 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-fired 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 electricity 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 projected 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. 

Comment 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 has 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 statespecific 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 the 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 this is not the way that an integrated electric system operates and that in 

order to have a reliable, efficient, and reasonably priced 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 intermediate 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 

factors 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 computation. For example, commenters 

stated that it makes no sense that EPA applied heat rate improvement in Block 1 then 

subsequently applied this lower CO2 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 well 
130

as examine how the individual building blocks will interact with or affect the achievability of 

each other.

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 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 requirement 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, but 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 redispatch generation through the grid, regardless of state or regional boundaries, based on costeffectiveness 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 should 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 stated 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).
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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 Mitigation 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 particular 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 

penetration 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 heat 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 system 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 highcarbon 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 

citations 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 that 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. 

Commenters 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 the 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 and 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 drive 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 zero-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 address 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 fired generation from increased zero-carbon and lowcarbon 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 

blocks.

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. 
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Response 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 public 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 while 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 energy 

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 

CO2 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 reality 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 generation 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 through 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 

acknowledge 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% renewable energy goal as proposed by EPA under Block 3 
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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 or 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 them 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 commenters:

• 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 be 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 efficiently 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 (redispatch 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 beginning 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.

Commenters 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 once 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 negatively 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 ratepayers 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 generation 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

maintain 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 the 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 subject to 111(d) regulations.

Commenters noted that the agency requests comment on how emissions changes under a ratebased plan resulting from substitution of generation by new NGCC for generation by affected 

EGUs should be calculated toward a required emission 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 provided 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 distributes 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 reliability 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 was 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 

Mississippi. 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 stated 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 generation 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. 

Commenters 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 somewhere 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 with 
137

largely instate hydroelectric 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 changes 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 determine 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 that 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 

located. 

• 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 an 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 offset 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 often 

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 200,000 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 renewable 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 energy 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 building 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 implemented. 

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. Commenters stated that reducing Block 1 generation by Block 2 redispatch 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 necessary 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 majority 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 increase 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 target 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 another 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 already 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 established 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 criteria. 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 following 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 provided by 

other building blocks. Commenters stated that EPA's justification to overlook any technical or 
140

economic issues identified with each building block based on flexibility provided by the 

incorporation of other building blocks undermines the severability 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 targets, 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 

unrealistic 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 revised 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 stated 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 

continued 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 existing policies in Arizona are likely to contribute 

significantly towards Arizona'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 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 following are summaries of the specific public comments under 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 EPA 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 stated 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 

underperform 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 their 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 that 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 combinations 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-dispatched 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, commenters 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 lowcapacity coal units in New York. 
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 

York 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 peak 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 significant 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 cost-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 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 

efficiency 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 expected 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 generation 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 fuels 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 unfeasible. 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 capacity of units that are still under construction), 

eliminating any potential state flexibility in implementing the Building Blocks. 

Commenters questioned the assumption that states can freely over-comply with any of the 

building blocks to address any shortcomings 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 coal 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, which 
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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 EPA’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 specific 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 in 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 Tennessee'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 compliance 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 many 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 asserts. 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 

NERC 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 wind 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 requires 

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 climate 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 

nuclear". 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 that 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 "cannibalize" 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 example, 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 net 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 verified 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 disagrees. 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 generation 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 decreases 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 for 
147

pathways that states can choose to implement the final 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 to 

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-emission 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, such 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 EPA'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. See 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 Block 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, EGU 
148

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 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 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 NGCC 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. 

Commenters 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 minimum 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 stated 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 capacity. 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 rate 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. Far from affording 

states flexibility in achieving overall emissions reductions, commenters asserted that the 
149

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 improve 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 expect 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 add 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 necessary 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 national 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 natural 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 are 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 constraints 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 NGCC 

plant is currently under construction. Commenters stated that one of the smaller NGCC units is a 
150

retro-fitted coal-fired unit with old boilers. Commenters stated that without appropriate 

verification of operating permit limitations, water supply, fuel supply 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 commencing 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. Commenters 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 expectations 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 their 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 involves 

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 operated 
151

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 met 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 and 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 coal 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 parasitic 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 promoting 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 which 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 comment:

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, commenters noted that the EPA relies on 
152

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 Building 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 that 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 are 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: Commenters 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 following 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 

experience 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 projected 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, commenters 

stated that a balance of various resources options must be employed to ensure 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, produce intermittent generation that can 
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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 

maintain 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 renewable 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 electric power system.

Comment 40: Commenters stated that the building blocks must be holistically integrated, or

the States risk the "German problem" of high costs caused by new investment coupled with

high CO2 emissions from fossil EGUs still needed for grid reliability.

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 summaries of the specific public comments under this comment:

Commenters stated that, as described in the FinAdvice report, Germany's approach to

renewables has resulted in higher power costs, a financially weakened power sector, and

ironically no real CO2 emissions Reductions. Commenters stated that, as illustrated in the

CAISO 'Duck Curve', provided by the commenters, steep ramping needs and over generation 

risk will require flexible generation. Commenters stated that these operational and integration

constraints put the third Building Block in conflict with the first two.

Commenters noted:

• First, the Building Block 1 Heat Rate improvements depend on the operational

environment. Increasing Renewable Generation will cause cycling, part-load

operation, and more frequent startups and shutdowns that will degrade Heat

Rate improvements.

• Second, the ability to achieve the Building Block 2 Dispatch increases at older

Natural Gas Combined Cycle Plants will be impaired if Duck Curve overgeneration risk becomes widespread. These plants would also be subject to

cycling and part-load operation that will impair Heat Rates.

• Third, greater Renewable Generation (Building Block 3) will necessitate

dispatchable power from gas-fired peaking plants or energy storage to maintain

grid reliability. High Heat Rate peaking plants are expensive to operate and
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will offset the emissions reductions of the Renewable generation, and

expensive batteries will drive up energy costs and impair economic growth.

Commenters suggested that rather than viewing renewables and conventional fuel sources in

opposition, they can be synergistically hybridized to economically achieve large reductions of

CO2 emissions at lower cost. Commenters stated that these benefits arise because the efficient

hybrid systems enable greater renewable generation with far less fuel consumption than

conventional peaking plants used to overcome intermittency. Commenters noted that the

benefits of hybridization are illustrated by hybrid automobiles, which demonstrate the synergy

of mechanical and electrical propulsion systems.

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 as 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.

Commenters stated that including these considerations in the CPP will enable the States and

the United States to achieve reduction of CO2 emissions more quickly and more costeffectively.

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

Commenters 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 achieve 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 to 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 the 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 states 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, particularly 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 experience 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 appropriate 

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 manner

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 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 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. 

Commenters 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 coal and nuclear 
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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. 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 stated that one of the great fallacies of the rule is that it would reverse the 

traditional functions 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 down 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 to 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 include 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 essential 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 sufficient 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, 

potentially 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 that 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. Commenters 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 capacity 
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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 contrast, 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 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 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 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. 

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 

coal 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 because 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 designed to operate as base load plants, they become less 

efficient-and hence produce more CO2 per MWh, if they are forced to cycle.
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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 CO2

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 reference 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 mandatory, 

but that it can be used as an option to obtain CO2 and other pollutant reductions.

Response 1: The EPA agrees that coal-to-gas fuel switching in existing coal-fired EGUs is an 

important CO2 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, but 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 the 
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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 technically 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 

co-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. Commenters 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 included 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 certain 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 performance 

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 pollution 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 gas 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.

The following are summaries of the specific public comments under this comment:
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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, and 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 source 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 effects 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 modifications 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:

Commenters 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 Proposed Rule states that it would reduce nationwide 

CO2 emissions from the power sector by approximately 30 percent from 2005 levels by 2030. 

Commenters believed 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 passage of the Powerplant and Industrial Fuel Use Act in 1978 by 

Congress restricted the construction of natural gas-fueled power plants and that electric utilities 
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were not allowed to construct new natural gas plants until passage of the Natural Gas Utilization 

Act of 1987, which repealed the provisions of the Powerplant and Industrial Fuel Use Act. 

Commenters stated that federal 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.

Commenters 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 

this 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-term 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 that the 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 timetables 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 acceptable 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 much 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 control systems, pipeline proximity, pipeline capacity, natural gas residential to 
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industrial breakdown, long term natural gas supply, natural gas interruptions, and costs/benefits 

of alternative emission reduction methods.

Commenters provided more detail on 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 switching, 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 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 stated 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 that other 

factors that cloud 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 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.

Combustion 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 only 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 less 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 fuels would 
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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 availability 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 equipment. 

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 percent 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 not 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 ammonia 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 formation. 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 degree 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 operation 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). Commenters 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 coaldesigned 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 to 
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some or all of the components mentioned above. 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 to 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 stated 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 cloud 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 natural 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 meet 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 gas 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 capacity 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 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 $80MM for a 20 mile long pipeline. 

Commenters stated that where mainline expansion or additional compression is required, costs 
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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, prompting 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 offering 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 firing 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 therefore 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 

will 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 circumstances 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 discussion of nonBSER measures that reduce CO2 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 Mitigation Measures TSD of the 

proposal.

The following are summaries of the specific public comments under this comment:
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Commenters stated that conversion to natural gas from existing fossil fuel-fired utility boilers 

and IGCC units should be part of the BSER. Commenters 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 will 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 stated 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 costeffective 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-togas conversions 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 

burn 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 carbon 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% natural 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 converting 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 pollutant 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.
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• 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 of 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 building 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 from 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 conversions 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 

projects 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 characterize them as a BSER option. Commenters believed that a more granular, stateby-state analysis is necessary. Commenters said a state-by-state analysis would show that in 
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many states, fuel-switching can be highly cost effective. Commenters stated that EPA 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 following 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 infrastructure 

nearby and/or costly efficiency and capacity penalties.

Commenters 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 coal 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 $80MM 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.
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Comment 6: Commenters stated that the EPA should treat coal-steam units that switch to natural 

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-fired 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-specific 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 this 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 plants 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 pollution 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 

Rulefor a discussion of the rationale for applicability.
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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 requires 

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 submit 

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 compliance 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, and 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 performance, 

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 

CPP
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• In contrast 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 occur 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 source 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 not 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. Commenters 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. Commenters 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 they 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 compliance 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 Louisiana 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 preamble 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 exempting 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. 
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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 Rule 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 surrounding 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. Additionally, commenters stated the fuel is bulkier, 

and therefore more transportation emissions will be created than would be with coal.

Comment 4: Commenters questioned the NREL evaluation of biopower that the EPA used in its 

initial estimates of renewable 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 comments 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, because 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 feedstock. 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 the 

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, outweighing 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 plants can actually burn crop residues for fuel, as is shown 
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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 storage 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, since 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 the 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 reductions 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 reference 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.
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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 that 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 gains 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 Rule. The CPP Final Rule 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 available 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 following 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 reclamation 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 with 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.
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3.8 CARBON CAPTURE & STORAGE

This section discusses the implementation of carbon capture and 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)), 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. 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 are also provided for these topics. (Below the response, 

comment summaries are noted.)

3.8.1 Post-combustion capture

Comment 1: EPA Should find that partial CCS is an alternative adequately demonstrated system 

of emission reduction

Response 1: These 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:

Commenters 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 reductions 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 CCS 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, partial CCS satisfies the statutory criteria for BSER:

CCS is adequately demonstrated for retrofit to existing EGUs.
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Commenters stated, as EPA documented at length in the TSD for the proposed carbon pollution 

standards for new EGUs, the individual technologies 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 several 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, equipped 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 metric 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-fired 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 coalfired power plant designed to employ 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 

standards 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 required 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 

meet 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 of [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 'available 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 must 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 instance, 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 Clean 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 the 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 

burning 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 controls.

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 requirements 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 demonstrated 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 Id. 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 Id.

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 sequestration 
178

of CO2 is available and adequately demonstrated. Commenters said, EPA has cited to numerous 

CO2 commercial storage projects as well as field studies that demonstrate 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 deep 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 indicate 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 availability.

.

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; Essex 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, 

furthermore, 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 factors 

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, 486 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 level, 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, 

likewise, 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 electricity 
179

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 affect 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 install 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 national 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 impacts - 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 of 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 authority 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 sense," 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 streams 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, revenue 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 revenues 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 finalized 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 functionally 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 

from 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 proposed 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 allow 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 

retrofit 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-equipped 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 

requirements 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 located 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 the 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 consideration does not bar the Agency from selecting CCS as the BSER because section 
181

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 EPA 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 demonstrated" even though some existing 

units may not be able to meet the resultant standard. See Id.

Commenters stated, furthermore the difficulty that some existing sources might have in adopting 

CCS due to site-specific spatial constraints or distance from CO2 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 to 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 adjacent 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 feasibility 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 necessarily 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 addition, 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 

predicted 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.

Commenters 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 this 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 performance 
182

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 long 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 industry 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 consumption. 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 had previously deemed PM regulations for EGUs to be reasonably costeffective 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 

availability 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. Commenters 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 significant 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 

(600 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 those 

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 BSER 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, 

the EPA disagrees that CCS technologies are not proven. The components of CCS – capture, 

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 comment:

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 source 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 Proposed 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 (nuclear, 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 on 

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 projects 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. 

Commenters 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 cautioned: "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 facilities 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 their plans to meet the emissions reduction requirements. Commenters 
184

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 will 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 be 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 demonstration, 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-wide 

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 technology 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 an 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 capture 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 not 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 

deploy CCS on a commercial scale. Commenters said that, both have been approved to receive 
185

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 even 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 potential 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 reasons 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 fossil 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 stated that CCS has not 

been adequately demonstrated. Moreover, 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 largescale 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 

demonstrated for all sources that will have to comply under the rule, which is all existing coalfired 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 section 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 the 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 half 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 further 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 technology itself fails to meet the definition of being adequately 

demonstrated. Commenters said that one million tons per year of CO2 storage is the amount 
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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 processing 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 measured 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. Commenters 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 pressure 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 

implementation 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 that 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 that, 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 said 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 constrained 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 said 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 increase. 
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 technology 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 flue 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 viable 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, insufficient, 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 respect 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. Commenters 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 IGCC 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-monetary 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 state's carbon emission rate target.

Comment 3: Commenters stated adding CCS technology to a biomass facility can lead to a net 

sequestration of carbon.
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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 such 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. Commenters 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 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 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 reduce 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 carbon 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 preferable 

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 Final Rule and also 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.
189

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

Commenters 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 small 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 submitted 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 patent, 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 technologies 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, 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. In addition, the EPA does encourage the development and deployment 
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of advanced and 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 

Building 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. Commenters 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 inclusion 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 

atmosphere. 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 there 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 may 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 response, 

comment summaries are noted.)
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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 storage 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 Injection 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 CO2 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 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 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 Office 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 geological 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 Measures 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 is 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 statewide 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 the 

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 measure 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 blocks" 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 stated 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 recognition 

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 impose 

appropriate monitoring and reporting requirements, as is required of CCS projects. Commenters 

stated this approach also appropriately constrains section 111 regulation to electric generating 
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units. Commenters stated that Section 111 does not authorize EPA to regulate mobile sources, 

and it would therefore be inappropriate to attribute emissions from the combustion of CCUderived biofuels in mobile sources to the EGU as suggested in the New Source proposal. 

Commenters stated such attribution of emissions would 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 Reporting 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 

further 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 that 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 reductions 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 while 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, 

alongside 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 opposed 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 that 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 achieves 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 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 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 existing 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 statespecific 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 the 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 stated, 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 and 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 state 
195

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 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 that 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 buydown for costly early-mover CCS projects. 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 CCS-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 Rule. However, 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. Comments 

maintaining that use of captured CO2 for EOR results in a negative CO2 balance, considered 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 CO2 utilization can result in significant increases in the volumes of CO2

stored per barrel of oil recovery, and thus result in a significantly greater amounts of CO2

avoided and sequestered associated with CO2-EOR. Also as explainedunder section 111 b Final 

Rule standards, recent scholarly work also notes that sources of CO2 derived from coal as a 

source of CO2 for EOR result in about 31% lower net CO2 emissions per barrel of oil recovered 

compared to natural-source CO2-EOR. CO2-EOR has been successfully used for decades at 

many production fields throughout the United States, and is expected to continue for the 

foreseeable future. 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 fuel costs in addition to 

the long term cost of purchasing CO2. These costs are balanced against the long-term demand for 

oil and the price EOR owners or operators can receive for the additional oil produced throughout 

the lifetime of the project. EOR operators will obtain CO2 from the most cost effective reliable 

source to make their projects viable. New sources of natural CO2 are available and awaiting the 

right market conditions for development.Similarly, many anthropogenic sources other than 

EGUs such as gas plants are available to support the oil industry’s expansion of EOR as market 
196

conditions allow. Thus, the industry is not dependent solely on the CO2 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 burned 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.

Commenters 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 sources 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 economical (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 emissions 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 

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. See also the preamble and supporting documents of the companion section 111(b)
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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 currently, 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 might 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 captured 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 stated 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 costs 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 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 does not agree that the rule would discourage use of EOR. The EPA has 

procedures in place to ensure safe and permanent storage of CO2 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 under GHGRP subpart RR will not change the status of a UIC 
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Class II well and that 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. 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 member 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 Reporting 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, and 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 commenters’ assertion that subpart RR requirements will 

result in EOR operators avoiding the purchase of CO2 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 relatively 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 case scenario) to 

approximately $2 per metric ton of CO2 (high scenario). Using a range of scenarios (that 

included high end estimates), these subpart 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 CO2 by EOR operators, even beyond 

current natural sources of CO2. For example, recent work by DOE has concluded that future 

development of EOR will need to rely on captured CO2. In addition, the Internal Revenue Code 

section 45Q provides a tax credit for CO2 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 performance

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 of 
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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") 

retrofits 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. Commenters 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 

CCS-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 proximity 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 stated 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 

under the UIC Class II Program and the use of anthropogenic CO2 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 available 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 activities, 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 coalfired and IGCC plants, and its recognition that such projects will be most economically viable 
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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 wells 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 plants 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. Commenters 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 cost-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 Radiation 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 

directors 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 statements 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:

Commenters 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 operations; however, if 

there is no increased risk to USDWs, then these operations would continue to be permitted under 

Class II.
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3.8.4 Retrofit CCS: technical feasibility

This section discusses the technical feasibility 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 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 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 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. See sections V.A of the Final Rule preamble of the section 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 following 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 

projects 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 comments 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 is 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. could 
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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 2030, 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 reflect 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 coalfired 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 implementation 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, sitespecific 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 due 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 an 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 CO2 into various 

stratigraphic layers of the Appalachian Basin formation, injection pressures and flow rates were 

deemed insufficient for adequate CO2 storage. Commenters also referenced a study by AEP and 

Batelle and the Mountaineer Power Plant during which AEP considered expanding the scope of 

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 engineering 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 validation-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 CO2 capture and sequestration as the ultimate 
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goal, CO2 capture and sequestration is not a cost effective and reasonable approach to CO2 

reduction. Commenters stated that it understand that the potential for CO2 capture has been 

demonstrated on very small scales, but that the technology is in its infancy and has not yet been 

demonstrated or made available on a commercial scale. Furthermore, Commenters stated the 

costs of CO2 capture at even a limited scale are far beyond what they consider reasonable within 

the context of BSER. Commenters 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 economic 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 CO2 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 demonstrated. 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 subsequent 

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 

available 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 coalfired unit 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.
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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 improvements 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 withdrawal 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 the 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 

offsetting 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 partial 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 prospective 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 available, 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 be 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 pledges 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 technology 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 stated 
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that unless and until some fundamental breakthrough in chemistry and material science, EPA 

need not indulge utility pledges of future science fiction.

Commenters stated 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 available.

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 its 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 

considerations 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 appropriate 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 mineral 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 standard 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 plants 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 

completed 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. 
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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 rate 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 by 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 transition 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 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. 

Therefore, the EPA agrees with the commenters that “CCS retrofits are available”; but, we do 

not believe that 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 additional 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 assumptions 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 determination that partial CCS was adequately 

demonstrated and a BSER for new fossil fuel-fired steam EGUs and IGCC plants, and that CCS 
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retrofits are demonstrated at existing EGUs, referencing Plant Barry, SaskPower's Boundary 

Dam, and W.A. Parish. 

Commenters 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 existing 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 the 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 states 

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 sources.

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

Commenters stated the Boundary Dam project, along with the SaskPower 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 learnings 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 the 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 industrial 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 percent 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 sold 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 Centre, 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 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 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 – 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 EPA’s response to this comment.
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The following are summaries of the specific 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 partial 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 geologically 

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 universal 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 to 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 steam 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 finding 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

board 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 available space and 

near an EOR opportunity.

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

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 reference. 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 with 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.

Response 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 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 North Carolina 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 storage 

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 

discussed 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. 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.

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 technology 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 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 as currently designed, the Allam Cycle technology that NET Power is 

developing 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 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 the EPA exceeded its authority in determination of CCS.
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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 specific 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 Act 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 

compliance 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.

The 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 those 

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 respect 

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 control 
214

equipment, whereas in contrast, a new plant with CCS requires capital 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 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. 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 the 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 operation 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. Commenters 

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 revenues 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 project 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 CPP 
215

IPM runs using the assumptions found in EPA Base Case v5.13. 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 Injection 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 and 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 

significantly 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 closer 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 contrast, 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 existing 

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 CO2 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 any 
216

new or retrofit existing natural gas units. And coal unit retrofits are limited to 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 costs.

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 retained 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: Texas, 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 (NEEM) 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 and 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 in 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, the 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 

CO2 transportation and best estimates of retrofit costs. Therefore the most likely result is 85 
217

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, system 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 EPA 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 summaries 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 an 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 permit 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 also 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 plant, 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 approaches.

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. Commenters 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 stated 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 claims 

"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 EPA 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 site-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 progress 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 effective 

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 proposed nor 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 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:
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 

section 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 claims 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.

Referencing 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 only 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: Commenters 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 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 
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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 under 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 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'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 contribute to the substantial carbon dioxide emissions reductions required of 

the US power sector in the coming decades. 
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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 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 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 atmospheric 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 firms 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 

technologies.

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 benefits, 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 encourage 
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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 partial 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 that 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. Commenters 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 the 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 Clean 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 develop 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 carbon 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 

realistic 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 revelations 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 policies 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. 
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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 include 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 associated 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 

opportunities – 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 efforts 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 shown 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 CCSEOR retrofits are significant when compared with the sum of the CPP's state 

emissions reductions 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 CCSEOR retrofits can account for between 4 and 16 percent (depending on the 

scenario modeled) of the U.S. total CO2 reductions under the CPP."
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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. 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. These projects – along with 

other projects such as the Kemper County IGCC facility and the Boundary 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 capture 

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 promote 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 federally 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 maintain 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 commercial 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 that 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 importance 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 nation'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 progress 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 and 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 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 – 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 retrofitting 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 sector. 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 consideration 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 stated 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 Research 

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 the 
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CO2 reductions achieved through natural 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 challenging 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 that 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 firms 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, 

property, 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 favorable 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 included 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 critical 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 acknowledges 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 the 
227

enormous impact that the proposed rule would have on existing infrastructure, EPA is 

encouraged 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 capture 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 sources 

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 technology 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 reductions 

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-line 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 Clean 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 overall 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 already 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 emissions 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 Blocks 

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 introduced 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 CO2 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 written 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 increase 

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 reductions is 
229

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. Commenters 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 

commercial 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 (comments) 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 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 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 products, 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 pressurized 
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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 recycled 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 certainly 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 marketbased alternative 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 references on the commenters' 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 the 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 added 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, meeting 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-refineries 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 entrepreneurial 

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 policies will enable the development of new technologies that have 

the potential to significantly reduce CO2 emissions. 
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Commenters agreed that the EPA should recognize CO2 reductions resulting from innovative 

approaches to carbon utilization and recycling. Commenters 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 rule, 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 affirmative 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 timeframe 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 

credits 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 difference 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.
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Commenters said that if emitters can profit greatly by the sale of CO2 to Algenol, this will 

ensure 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 encourage 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 compliance 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 that 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, substituting 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 reliability 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 specifically 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 consider, particularly with respect to 

strategic technologies such as CCS. Commenters requested EPA clarify that all emission 
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reductions resulting from early actions taken after the date of proposal should count toward state 

compliance. Commenters emphasized this 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 recognize 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. Commenters 

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 opportunity 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 projects.

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 policies 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 regulated 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 that EPA's encouragement of CCS projects is fully consistent with 

the Agency's conclusion that CCS technology is commercially viable today.
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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 Final 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 the 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 benefits 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 equipment, 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 reductions.

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 require 
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states to develop plans that explore and recognize developing 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 utilization 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 affirmative 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 clearly 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 captured, 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 represents 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 project 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 expense 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 offers 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. Commenters 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 ongoing 

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 combustion. 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 algaebased CCU versus application of CCS for the same power generation facility. Commenters stated 
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that the analysis 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 emissions 

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 in 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 approval 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 emissions 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 stated 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. 

Commenters 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. Commenters 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 

and 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 recipients 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 discussion 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. Commenters 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 for 
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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 management 

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 carbon 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 100 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 emissions 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 to 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 disposal 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 

carbon 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 algae-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 CO2 
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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 

produced 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 development.

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 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 stated EPA should allow 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 Final Rule for section 111(b). Also 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

Comment7: Commenters stated the elimination of burning 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 section VIII.I.2.c and section 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 appropriate. 

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 storage 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 coal 

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 documents section 111(b)of the 

companion section section 111(b) standards for GHG emissions from new, modified and 

reconstructed sources.

Comment 10: Commenters asked for clarification regarding use of CCS projects in goal 

attainment.

Response 10: 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.
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The following are summaries 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.

Commenters 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 possible 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 

itself 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 truck 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 fertilizer 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 suggest 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:
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Commenters stated EPA should include language that recognizes the viability and benefits of 

developing carbon capture and sequestration in cement, building and road materials. 

Commenters 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 CAPACITY

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 new 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 summaries 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 years. 

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 final 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 must 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 wellunderstood technology. Commenters added that this conclusion is affirmed by the IPM 

compliance 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 described 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 in 
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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 

costs 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 pipeline 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 

capacity, 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. Commenters 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 units 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 source 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.
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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 that 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 capability 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 generation 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 artificially 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 while 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 particular 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 presumably 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 standard, 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 whether 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 additional 

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 high cost, in addition to the complicated siting and 
244

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 throughout 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 components 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 not 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 same 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). 
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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 NGCC 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 that 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 units 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 component 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 subject 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) requirements 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 states 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 since 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 

defining 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.
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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 remain 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 for 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 

because 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 within 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 capacity 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). Commenters 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 the source itself or within the source category, and may not include beyond-theunit 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. Commenters 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 incorporate 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 that 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 generation 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.

Commenters 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 measures 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 are 

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 emission 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 

construction 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 programs, 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."
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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 comment:

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 explicitly 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 utilize 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 NGCC 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 NGCC as a compliance mechanism both for affected EGUs 

(by allowing 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 

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 

CO2 reduction 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 disadvantaged 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 CO2

emissions. 

While increasing the proportion of fossil-fuel generation to NGCC EGUs with lower CO2

emission rates may reduce (or proportionally lessen any increase to meet higher demand) statewide mass CO2 emissions, commenters said that unless all states are permitted by rule the option 

of accounting for new NGCC will have little to no impact on state average CO2 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 is 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 designating new NGCC as an affected entity under the proposed 
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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 all 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 the 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 stated 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 

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 units. 

Commenters said that to hold "new" units modified or reconstructed to burn 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 CO2 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 for 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 of "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, Subpart 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 that 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. If 
250

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 goal.

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, 

within 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 the 

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, commenters 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 clarification 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 resources 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 renewable 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 the 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:
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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 greenhouse 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 

should 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 significant 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 sources, 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 states 

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 nation 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 allowable 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 

well 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 is 
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affirmed by the IPM compliance 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) demonstrates 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, Comparison 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 Power 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 emission 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. Commenters 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 conditions. 

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 budget 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 program 

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 increasing 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-fired 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 NGCC 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 analysis 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-represent 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). Commenters 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 from 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 hours 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 generation 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 compelling 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 

CO2 $/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 sources 

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 

higher 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 They 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 with a new NGCC facility would 

reduce the net CO2 emission rate of the generating capacity by 62% at a cost of about $50/tonne 

of avoided CO2 under the base case projected gas price and about $81/tonne of avoided CO2 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 power 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 represents 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 costs 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 targetsetting 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 methodologies, commenters added, the states would not be limited 

in their compliance options and could achieve the targeted emission reductions through any lowor zero-emitting technology, should that option prove more competitive in the particular state.

Commenters 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 in 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 projects 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 announced 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 compliance (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 higher 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 1,030 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.
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Comment 7: The use of new NGCC units to displace coal generation and reduce emissions 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 pathways 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 specific 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 

building block should explicitly include new NGCC on the compliance side through a massbased allowance trading system. Commenters stated that the use of new NGCC units to displace 

coal generation and reduce emissions is "adequately demonstrated" by recent electric 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 resulting 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 generation, 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 NGCC 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 redispatch effect from the new NGCCs presents 

the opportunity for additional, cost-effective CO2 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 that 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 CO2 emissions is clearly "adequately demonstrated" as a CO2 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 CO2 emissions. Commenters said 

that states should therefore evaluate (in their state goals) the emission reductions predicted due to 
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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 demonstrated."

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 cheaper 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 came 

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, CO2

pollution from the power sector has fallen sharply. Commenters 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.

Response 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 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 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 specific 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 must direct states to account for the CO2 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, commenters 
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said that a state could achieve emission reductions from affected sources by reducing 

corresponding generation and constructing new plants to serve the remaining 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 budget 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 shift 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 halfcentury or more.

Commenters said that the current structure of the CPP may create perverse 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 to 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 target-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 

count 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. Commenters 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 disparities 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 tools 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 symmetry 

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 for compliance purposes
259

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 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 EPA 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 potential 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. Commenters 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 units 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 unavailability 
260

of an adequate natural gas supply delivery infrastructure 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, Wisconsin, 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 BB2. 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 the 

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-site, coal-toNGCC 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 redispatch 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 BSER 

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 into 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 uncertain 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 CO2 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 said 

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 "remaining 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 CO2 emissions 

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 technologically 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 estimates that reducing emissions through cofiring would cost as much as $150 per metric ton of CO2, while reducing emissions through redispatch 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 reduction) 

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 evaluated 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 section 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 

section 111 (d) compliance, earlier retirement of coal-fired units will be encouraged. 

Commenters added that if this option is allowed both the emissions and net generation should be 

included in the CAA section 111 (d) compliance calculation. 

Commenters said that the EPA does not address how NGCC generation and 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 NGCC 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 generation 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 finalize 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 adequately 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 additional 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 

goals 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. 
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Response 11: 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 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.

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 for 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 strategy 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 steam 

generation. Commenters said that the CPP must recognize the critical role of new natural gasfired 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 non-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 NGCC 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 that 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 purposes 
264

of 111(d) compliance while new gas generation would continue emitting, undermining 111(d)'s 

goal of reducing electric sector greenhouse gas emissions. 

Commenters 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 clarity, 

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 section 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 said 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" facilities 

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 incremental 

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 required 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 CO2/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 subject 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 compliance 

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. Commenters 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.
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Commenters agreed that new construction is needed in Arizona to meet summer peaking demand 

requirements in Arizona and adjacent states and 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 costs 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 deployed 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 heat 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 unit 

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. 

• States 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. 
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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 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 specific public comments under this comment:

Commenters stated that the EPA should allow states 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 supported 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 portfolio 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 new gas.
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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 increased (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 reciprocating 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 capacity 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 different 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 plans 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) Commenters 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 different. 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 CO2 emission standards for new units were proposed (January 8, 2014) and which 
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are in compliance 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 for 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 address 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 lowcarbon 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 correspondingly 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 replacement 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 meet 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 new 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 CO2. Commenters concluded 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 units 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 with 
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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 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. 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 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 purposes 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 Virginia 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. Commenters 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 Plan, 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 emission 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 

average emissions rate used for compliance, it can displace some generation from covered 

sources and thus indirectly lower the average emissions rate from covered sources.”
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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-state 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 supported 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 performance 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 generation 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 periodically 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 carbon 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 that 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). 
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Currently the EPA's proposal 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 

while 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, including 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 compliance, 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 that 

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. Commenters 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 mass-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 compliance 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 require 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 EPA 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 into 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 existing 
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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 that 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 downward 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 of 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 megawatts 

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). 

On 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 rule 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 new 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 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 noted that state rate-based goals would still be based upon emission 

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 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 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 that 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 state'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 instate load. Commenters said that a state whose new natural gas generation simply displaces 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 and thus increase its net exports (or, 
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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 performance 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 extent 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 or 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, 

commenters 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 demonstrate 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 NGCCs 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 lower 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 compliance 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 

processes 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 functionally 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 render it an unlikely choice for many states, 
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commenters said that new NGCC units may be needed for a variety of reasons, including: costeffective integration of variable renewable resources, provision of other grid reliability services, 

and satisfying increases 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 with the 

state emission rate goal. 

Commenters said that new NGCC MWh of generation must be credited by the EPA as a zeroemission generation source because the EPA has failed to reconcile its flawed approach in 

requiring some states to meet more stringent emission 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 affected 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 that 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 States 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 that account for not only carbon dioxide, but the fullcycle 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 established 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 control 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: 
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• 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 EPA 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 existing 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 compromising 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 

establishing 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 rate 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 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 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 gas 
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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, uncapped 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 incentives are distorted one way or another under both the mass-based and ratebased 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 

existing sources under the same mass-based standard would eliminate the incentive to overinvest in new generation. 

Commenters noted the EPA's requests for comment on how emissions changes under a ratebased plan resulting from substitution of generation by 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 reductions 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 

compliance, 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 the 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 resulting 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 provisions 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 outside 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 that 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 this 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 between 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-
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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 

utilization (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. Because 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, but 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 muted 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 run 

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 massbased ones.

Commenters said that excluding the emissions and electricity 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 (or 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 stringent 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. 

Commenters 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 EPA 

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 allowing 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 other, similar incremental emission reductions that could 

also be applied toward compliance with the section 111(d) program.
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Commenters said that their ability to comply with the CPP is dependent on compliance via ratebased goals, and that they must be permitted 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 going 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 high 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 compliance, 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 emissions 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 units. 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 units.

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 stringent 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 because 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 functionally 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 because 

of cost and long lead times, and that as a result new NGCC units may be needed. Commenters 
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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 emissions 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. Commenters 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 not 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 existing 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 push 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 ratepayers 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 remaining 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 economically 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 EPA can, within 

the structure of Section 111, periodically broaden the scope of affected EGUs by revising the 
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GHG NSPS for stationary turbines at least every two years, so that, upon revision, stationary 

combustion turbines that were constructed after January 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 setting 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 review 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 affected 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 emission 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 

the 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 facilities 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 NGCC 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 infrastructure (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 unit 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, 
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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 Proposed 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 energy 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 displace 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/or 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 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 specific public comments under this comment:

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.
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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 stringent 

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 states 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. 

Commenters 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 generation) 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. Commenters 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 anything 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 confines 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 target 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 targetsetting 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 power 
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plant. In other words, commenters said, although the proposal allows new NGCC to be used for 

compliance purposes, this opportunity is not actually available 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 nameplate 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 section 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 permitted 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 generation 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.
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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 the 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 allow 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 warming 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 long 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 necessarily 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 produced 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 ratebased targets by replacing older, more carbon intensive units with newer units, particularly 

NGCC units. Commenters continued, (verbatim) EPA appears to agree with this compliance 
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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 referred 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, EPA 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 New 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 

allowing 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 that 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 into 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 their 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 units 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 does the addition of New NGCCs (whether 

replacement, substitution or additional capacity). Commenters said the average rate remains 
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2000 lbs/MWh (now averaged over 3 units). See Scenario A below. Commenters said only if the 

emission rate from the New NGCC units 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 retired 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 

acknowledged, 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 based 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 credit 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 suggested, 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 requirement. 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. Commenters 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 units. 

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 states 
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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 this 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 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.

3.10 HEAT RATE REDUCTION OPPORTUNITIES FOR NON-COAL FOSSIL FUELFIRED EGUS

This subsection primarily addresses public comments which questioned whether the EPA 

properly estimated and included in its quantification of building 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 (comments) 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. 
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Some 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 significantly 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 capricious 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 fuel-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 gassteam 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/Gasfired 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 gas 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 

contradict 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 important. 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 

improvements 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 CO2

reduction potential of affected coal-fired EGUs. 

Some commenters stated that 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 

reduction achievable by application of best practices to NGCCs. We considered performing this 
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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 additional 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 reflected 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-factor 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 

the 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 building 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 uniform 

CO2 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 commenters' 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 emission 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.pdf
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Appendix to chapter 3 of the proposal and 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 target 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 there is a greater disparity among heat rates at gasfired 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 efficiency 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 the 

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 combustion 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 capacity 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, measures 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 coal combustion solid waste products. 79 Fed.

Reg. at 34,882. Commenters stated that there is no reason why EPA should not factor the 
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potential for heat rate improvements of natural gas-fired EGUs in setting the stringency of the 

standard, which would result in greater environmental benefits than currently estimated under 

Building Block 1. 

Commenters recommended that EPA should include heat rate improvements for oil- and gasfired EGUs in its determination of BSER for these units. Commenters also recommended 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 does 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 coalfired 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 electricity.

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 stated 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 difference 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, transport and distribution, and methane's 

proper GWP and leakage rate. Commenters stated that in any event, even if oil and gas steamgenerated power overall creates fewer emissions than coal-fired generation, that fact alone does 

not justify allowing this source 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 small 
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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 opportunities 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 demonstrated 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 comment 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 new 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 cycle 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 average 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 between 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 comparable 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 gasfired 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-fired units are significantly 
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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-term 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, and 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 that 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 proposed 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 fifteen 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 rates 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 EGUs 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 the 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 unit. 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 is 
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limited to coal and gas-fired units for which generation, heat rate, and emissions 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 

reported 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 for 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 lowest 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. Commenters 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. 

Commenters 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

Commenters 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 there 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 that 
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furthermore, the level of emissions reductions required for natural-gas fired EGUs should be 

based on 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 rate 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 groups 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-performing 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 their 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 improvement 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 account 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 

significant 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 One. 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 aggregate 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 generation 

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 Building 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 responsible for more generation in 

aggregate than natural gas, this is not true at the state level, the level on which EPA sets state 
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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 reductions 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. Commenters 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 

performance. 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, EIP 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 gasfired steam EGUs, EPA should calculate potential CO2 emissions rates by comparing poorer 

performing units with 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 best 

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 

Steam 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 rate 

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 that EIP's analysis of best performing natural gasfired 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 stated that here too, it is reasonable to expect that additional natural gasfired 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 currently 

proposed by EPA, EIP's analysis nonetheless represents a conservative estimate of possible 

reductions.
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Commenters stated that EIP's Findings Cast Doubt on EPA's Rationale for Excluding NaturalGas Fired EGUs from the Purview of Building Block One.

Commenters 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 ambient 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 would 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 opportunities 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 the 

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 Proposal. 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 required. 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 fewer 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 should 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 electricity 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 with 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 responsible 

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. Commenters 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 One.
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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 effective 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 stated that EPA must include natural gasfired 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 Building 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 emission 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 the Proposed Rule.
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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 not 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 2080. 

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 reduce. 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 without 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 even 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 detailed 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, 

lack 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 determines 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, 
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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-effective, 

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 every 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 used 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 demonstrated 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, however, 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 improvement. 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 practices 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 maintenance 
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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 AGP 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 of 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. Commenters 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 

improving 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 installed 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-up 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.

Commenters 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 Advanced 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. Commenters 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 create 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 Pack 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 Dense 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.
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Commenters 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 favored 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 calculations 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 coalfired 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 Twelve, 

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 illustrate 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 that these include the following: 
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• 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 chilling 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 enhanced 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 upgrades 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 rotor 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 opportunity 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 relied 

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 unit-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 stated 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)
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• "GE Combined Cycle Product Line 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 operated 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 combined 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 

for 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 redispatch 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-fired 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 heat 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 electricity 

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-fired 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 the 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 

guidelines 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 the likely equipment upgrades will also 

improve the reliability and durability of the unit - an important aspect that cannot be overlooked 
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given their increased role in providing electricity. Commenters stated that reliability and 

durability of gas units will 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 software 

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 highefficiency gas turbine 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 compress 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 these 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 constant 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 operation. Commenters stated that in the 

periods in which the units operate near full power, the four plants comprising 2x1 combinedcycle 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 1,130 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.

Commenters 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, the 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). (Permit 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 the 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-
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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. 1903-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 stated 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 dispatch 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 reconstruction 

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 reductions 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, which 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 values. 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. Commenters 
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stated that 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 commenters 

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 reasons given in 

response to Comment 1 in this section, the Agency is focusing its resources at this time on the 

larger CO2 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 improvements 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 compared 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 applied 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 in 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 through 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 available 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 rate 
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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 stated 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 emission 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 reductions 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 practice 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 applied 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 

improvement 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 uncertainty 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 not 

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 

familiar 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 over 
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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 combustion 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 best 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 already 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 yield 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, any 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. Commenters 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 those 

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 maintenance 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 period).
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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 Performance 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 that 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. Commenters 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 complement 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 minutes 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 little 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, President 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, synchronize 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 since 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 HRI 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 

increase 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 be 
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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 supported the Proposed Rule's 

exclusion of NGSC HRI from Building Block 1.

Commenters 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 that 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 general 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 that 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 improvements 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 maintenance 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 

defined 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 because 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. Commenters stated 
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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 that 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 targets.

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. Commenters 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 because 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 stated 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 for 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 City 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. 

Commenters 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 that 

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 determination 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 justified. 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 

modifications, 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 achieve 
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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 relatively 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 seeks 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 potential 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 

modifications 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, particularly 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 combustion 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 event 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 determine 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 air 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.

Commenters 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 stated that 

moreover, NGCCs and NGSCs (whether geographically isolated or not) should not be subject to 

Building Block 1 HRI.
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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 preamble 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 public 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 the 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 emissions 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 simple-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 contribution 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 these 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 units 

that operate at warm temperatures, using inlet air chilling or cooling preferentially to duct 
315

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 subcategories 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 exemptions, 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 EMISSION REDUCTION MEASURES 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 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: Alternative approach – ultra-supercritical plant designs

Response 1: New fossil 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 comment:

Commenters stated they believe that the EPA could have achieved similar reductions in CO2

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 supercritical 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 and 
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1980 and were a mix of sub and supercritical designs 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 efficiency 

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, operating 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 that 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 and 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. 

Commenters stated that replacing existing sub and supercritical coal plants with ultrasupercritical plant designs would, improve plant heat rates by 5.5-16% with an equivalent 

reduction in CO2 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 CO2 emissions without the use of yet-to-be-proven CO2 capture systems. 

Commenters presented for comparison some examples of coal plant efficiencies and CO2

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 included in their comments, replacing subcritical plant designs with ultra-supercritical systems would reduce CO2 emission by about 16% 

and if Advanced ultra-supercritical plants can be commercialized an almost 30% reduction in 

CO2 emissions per MWhr could be realized 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, CO2 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. 
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Commenters stated that replacing aging coal plants with more efficient ultra-supercritical plants 

would allow for a significant reduction in CO2 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 CO2 capture ready condition and CO2 emissions could 

be reduce now while waiting for cost effective CO2 capture technologies to be developed. 

Commenters stated that given the present cost to capture CO2 no new coal plants will be built if 

CO2 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 comment:

Commenters stated that this is a very important option and urged the inclusion of these to 

displace kilowatt hours from major power plants. Commenters stated this is important and it also 

helps resiliency of the agents. Commenters 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 address 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 current 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 CO2 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 programs 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 from forest feedstocks will reduce CO2 emissions. Commenters urged
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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 forests 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 assumption 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 specific 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 that 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 CO2 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 CO2

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 CO2 emission 

rate, provided they meet the general and specific eligibility requirements for resources used to 

adjust a CO2 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 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 CO2 emission rates. 

Provisions to encourage early action are discussed in the preamble in section VIII.B.
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The following are summaries of the specific public comments 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 the 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 that 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 states 

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 meet 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 MSWderived fuels like ABFuel, should be allowed to be 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-BSER 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 CO2 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 CO2 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 should 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 use 
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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 established). 

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 reproposal 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 allowed for consideration by EPA as it establishes its 

guidelines for existing source types. Commenters added if the EPA continues to insist on this 

approach, Then 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 rule 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; Electrification; 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 feasible 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 proposed 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 CO2 emissions from affected 

sources. Demand-side EE and other non-BSER measures are not used in calculating the CO2

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 CO2 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 CO2 emission 

rate, provided they meet the general and specific eligibility requirements for resources used to 

adjust a CO2 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, hydroelectric 

power, and biomass. Preamble section VIII.K discuss measures, such as CO2 emission reductions 

from outside of the power sector that may not be used to adjust CO2 emission rates.
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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. 

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 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 stressed that availability of clean energy solutions like energy efficiency, and wind 

and solar energy 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% - without 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 measures 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 Plan 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.

Commenters 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 natural 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 waste-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 receive 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 rates and potential disruption of 
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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 use 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 statelevel energy efficiency resource standards (EERS) and utility efficiency 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 in 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 efficiency (heat-to-electricity transfer rate) improvements at all fuelburning power plants (both coal and gas facilities) and maximize the development of zeroemission renewables.

Commenters encouraged the Agency to support strategies that are performance-based 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 goals. 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 geothermal, 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 defining 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 emissions 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 sequestration, state actions incenting energy efficiency improvements 
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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 resulting from utility's programs to count towards 

compliance.

Response 6: CO2 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

measures must reduce CO2 emissions from affected EGUs. A program that reduces CO2

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 for 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 as 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 discussion 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 VIII.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 important 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. 
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Commenters stated that 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-energy 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 Renewable 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 

utilization) 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 of 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-derived 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 electricity.

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 stated 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 concluding 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 emissions reductions. 

Commenters stated that Georgia has a program in place to monitor the sustainability of the forest 
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resource, including the Georgia Forestry Commission's Forest Sustainability Report, Forest 

Inventory and Analysis (FIA) and forestry Best Management 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 cost-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. Commenters 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 evaluated 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 often 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 should 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 from 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 

States 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 reductions 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 fence of the generator, and include 

reductions from decreased organic matter in landfills, displaced coal, and increased recycling.
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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 administration 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 wastederived and certain forest-derived industrial byproduct feedstocks." Commenters 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 specifically on sustainably-derived agricultural- and forestderived 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 mitigating 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 under 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 renewable energy resource and may be included in state plans as a non-BSER RE 

measure. 

The EPA addresses considerations for incorporating CO2 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 CO2 rate.

The following are summaries of the 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 said 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 other 
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emerging technologies 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 congestion 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 other 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 CHP 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 CO2 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 

specifically in section VIII.K on EM&V criteria for measures used to adjust a CO2 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 

ground-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. energy 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, flexible 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.
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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 said 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 periodically, 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 available 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 compliance.

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 CO2 emissions from affected EGUs and meet other state plan 

requirements. 

Direct air capture, while potentially benefitting the environment and reducing atmospheric 

concentrations of CO2, does not replace generation for affected EGUs or reduce stack CO2

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 CO2 emission reductions from outside of the power sector that may not be 

used to adjust CO2 emission rates.

The EPA addresses considerations for incorporating CO2 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 when 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 CO2 rate. 

The EPA understands that NET Power may have potential to generate power with very low CO2

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 innovative 

technologies for compliance. 
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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 stated 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 CO2

in the atmosphere. While the rule proposes four distinct approaches for the states to reduce 

emissions from 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 in 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 technology 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 plants. 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 additional 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 manufacturer'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 commercialization." 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 innovative 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 CO2 from 

ambient air. Commenters 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 energy, and demand-side 

strategies being proposed by the Agency as part of a "building block" approach to reducing the 
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environmental and public health risks posed by global climate change. Commenters urged the 

EPA not overlook the critical contribution that DAC 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, They have the potential to provide massive clean 

air benefits to the 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 CO2 emission reduction 

measures in state plans in section VIII.I 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.I For CO2 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% CO2

emissions for reclamation and that strategic air emission recycling (AER) would capture, sort, 

refine and distribute this 20% as CO2 derivatives to meet the needs of current and future markets. 

Commenters said that reclamation enables captured CO2 conversion into non-recalcitrants (dryice for refrigeration needs, specialty CO2 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 CO2

obviates "outside the fence" methods such as emissions trading and averaging. Commenters 

added that AER is comprised of systems that fix all CO2, which may be processed on demand 

into: 
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• Composted soil 

• Cellulose-based derivatives (products that cannot be digested or hydrolyzed for 

ultimate release of CO2 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 CO2 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. 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 CO2 emission rates in state plans under the emission standards 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 CO2 emission rates.

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

Commenters 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 CO2. Commenters stated that this system is 

based on a proprietary thermodynamic cycle, called the Allam Cycle, which utilizes oxycombustion in combination with a supercritical CO2 working fluid in order to drive a gas turbine. 

Commenters stated NET Power plants achieve a modelled net system 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 efficiency 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 $88.6-134.3/MWh for NGCC with carbon capture. If CO2 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. 

Commenters 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 noted 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 CO2 emission performance 
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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 CO2 emission rate, provided they meet the general 

and specific eligibility requirements for resources used to adjust a CO2 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 are described in Section VIII.K. 

Methane capture from coal mines or oil and gas wells, while potentially benefitting the 

environment and reducing atmospheric concentrations of CO2, does not meet the state plan 

requirements if it cannot be shown to replace generation from affected EGUs or reduce stack 

CO2 emissions from affected EGUs. Therefore, it is not considered an allowable measure in state 

plans using the emission standards approach for this rule. Preamble section VIII.K discusses

measures, such as CO2 emission reductions from outside of the power sector that may not be 

used to adjust CO2 emission rates. CCU applications 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 deployed 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 mining 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 

technologies. 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. Commenters 

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, and 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 

monetize 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 stated 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 technologies and services as they develop compliance plans. Commenters 

described the report as follows: 
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• The solutions in the report demonstrate the breadth of options that states have at 

their disposal today. 

• Technologies are grouped into three broad categories: buildings 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 

appliances, 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 submitted 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 encourage use of carbon offsets.

Response 14: Out-of-sector offsets may not be counted toward meeting a CO2 emission 

performance level for affected EGUs or a state CO2 goal, because out-of-sector offsets are not 

connected to the electrical grid and so cannot reliably address stack CO2 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 finalizing 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 CO2 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.

The following are summaries of the specific public comments under this comment:
334

Commenters encouraged the EPA to use carbon-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. Commenters 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 

additional 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 cap and trade programs the Northwestern and MidAtlantic 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 

mechanism, 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 the 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 

carbon 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.
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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 CO2 emissions from affected EGUs. The EPA addresses considerations for 

incorporating CO2 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 specifically in section VIII.K.3 on EM&V 

criteria for RE and demand-side EE resources used to adjust a CO2 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 costeffective 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 residents 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 natural 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 electric 

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/ourissues/ 

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 basis, 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 energy 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 same 
336

electric 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 generation.) 

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 policies 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 switching-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 block 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 added 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 gas 

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 disadvantage 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 electric), 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 reduced 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 reduce 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 loss 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 percent 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 of 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 and 
337

transporting natural gas to the customer. Commenters provided other references of the energy 

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 electric 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 thermal 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 where 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. 

Comment 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 projected energy impacts of this final rule. CO2

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 concerned 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 considering 

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 meaningful 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 in 
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renewable energy choices, and gas represents 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 atmospheric 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 said 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. Commenters agreed that starting with power 

plant regulation is important, but that it needs to expand out from there to look at other carbonintensive 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 CO2 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 VIII.K.3 on EM&V criteria for RE and demand-side 

EE resources used to adjust a CO2 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 gas 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 Portfolio 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 account the market potential of allelectric 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 reduce 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 

fuel cells. Commenters stated California's Self Generation Incentive Program provides a perfect 
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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 report, 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 reductions 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 emission 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 used 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 efficiency 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 noted 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. Commenters 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 improve 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 Ultrasupercritical designs using nickel based alloys 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. Commenters said with support from industry and the U.S. DOE, the 
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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 reduction 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 

high-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. Commenters 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 the 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 proposed 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 gas 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 rate, 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. 
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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 their 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 CO2 emissions from affected sources. Demand-side EE and other nonBSER measures that are tied to a state plan and achieve quantified and verified MWh savings 

may be used to adjust a CO2 emission rate, provided they meet the general and specific eligibility 

requirements for resources used to adjust a CO2 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 codes 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 Consortium 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 construction 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 Agriculture 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 ability to use electrification projects.
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Response 20: Electrification projects, while potentially benefitting the environment and 

reducing atmospheric concentrations of CO2, do not meet the state plan requirements if they 

cannot be shown to replace generation from affected EGUs or reduce stack CO2 emissions from 

affected EGUs and are not grid connected. The EPA addresses considerations for incorporating 

CO2 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 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 

atmospheric concentrations of CO2, does not meet the state plan requirements if it cannot be 

shown to replace generation from affected EGUs or reduce stack CO2 emissions from affected 

EGUs. The EPA addresses considerations for incorporating CO2 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. 

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 Trip", 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 economy 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 

recent 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." 

Commenters 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, vehicle 
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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 that 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 

determined 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 significantly 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 CO2, 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 CO2 emissions from affected EGUs. The EPA addresses considerations for 

incorporating CO2 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. 

Affected EGUs in states that choose a mass-based emission standards approach have several 

options for reducing CO2 stack emissions. Mass emission standards may not be adjusted upwards 

to account for vehicle electrification, which may result in increased CO2 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 choose 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 total electricity consumption, but will not directly impact 
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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 likely 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 throughout 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 inclusion 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 

the 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 compliance 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 policies. 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 they 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, commenters 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, it 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 additional 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 longer 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 on 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 

states 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 still show and increase in total 
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electricity demand and associated power plant emissions, making it harder to meet the massbased goals. Thus, commenters concluded, states will be discouraged from adopting additional 

policies to expand the use of EVs, and once 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 electrification 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 charging 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 clarify 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 electrification 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 

compliance more difficult for states regardless of whether they choose a rate-based or massbased 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. Commenters 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 possibility 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 

emissions 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 transportation 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 described 
346

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 massbased 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 California's case, 900- 537 = 363 pounds per 

megawatt-hour) may not be high enough to actually deter investments in EVs and other carboncutting load. Commenters encouraged the EPA work with states with ambitious EV programs to 

develop a solution that appropriately 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 minimizes 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 eliminates 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 adjusted 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 number 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 

Administration. 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 agency. 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 acceptable 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 electricity) 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 zeroemitting nuclear and renewable energy is added to the electric system, the net benefits of 

electrification would be expected to increase.
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Comment 23: Reduce idling emissions from diesel trucks.

Response 23: Reduced truck idling, while potentially benefitting the environment and reducing 

atmospheric concentrations of CO2, 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 CO2 emissions from affected EGUs. The EPA addresses considerations for 

incorporating CO2 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 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 specific public comments under this comment:

Commenters stated that another established CO2 benefit from electrification is shown in a DOE 

report titled "Energy Use and Emissions Comparison of Idling Reduction Options for HeavyDuty 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 emissions 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, particularly 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 CO2, 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 CO2 emissions from affected EGUs. The EPA 

addresses considerations for incorporating CO2 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 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 specific 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 savings that could be gained by promoting beneficial use of 

secondary materials, including coal ash. In measuring the reductions in emissions of greenhouse 
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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 components 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 

the 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 disposing 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 market. 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 plan 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-toenergy, 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 review processes could be used to 

inform how states and EPA assess biogenic CO2 can be found in Section VIII.I and Section 

VIII.K 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:
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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. 

Commenters 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 the 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 

calculated. 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 that 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'

calculations 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 is 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 indicates 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 methane 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 burning 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 

because 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 reduction 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 sequestration 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 water 
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supplies, and provide 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 

program 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 lbs 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: CO2 as chemical feedstock.

Response 26: Biodiesel from cooking oil, while potentially benefitting the environment and 

reducing atmospheric concentrations of CO2, 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 CO2 emissions from affected EGUs. The final rule gives states the 

flexibility, to use zero- and low-emitting resources to achieve their CO2 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 CO2

emission rate, provided they meet the general and specific eligibility requirements for resources 

used to adjust a CO2 emission rate, described in Section VIII.K. Carbon capture 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 electrochemical (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 bolt-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 

concerns 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 fracking and shale gas. 
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Comment 27: Various biomass feedstocks.

Response 27: A discussion regarding the use of some biomass feedstocks, including waste-toenergy, 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 

carbon 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 neutrality. 

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 methane 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 have 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 decrease 

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 and 
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regional haze, thus removing the need for unnecessary regulations and the potential need to shut 

down coal fire power plants.

Commenters 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-rating 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 such 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 (or $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 power 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 kilowatt-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 forever 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 switchgrass 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 "byproducts 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 clear, 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 "likely 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 materials-like urban wood, wood-derived 

construction and demolition debris, and railroad ties-be specifically included in the definition of 
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"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 reforestation, 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 electricity 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. 

Commenters 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 economic 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 

added 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 long-lived forest resources take too long to regrow 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 reduction 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 comment:

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 isolation, 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, wasting 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 

common 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 climate 
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mitigation. However, commenters stated, given the fact that in the United States 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 saw 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 also 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 18. Based on this report, commenters 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 residues.

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 rather 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 "importance 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 implemented 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 eliminate 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.
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Commenters stated that for biomass to be considered as a "renewable" resource full carbon 

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 sustainability. 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 substances, 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 critical 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 disturbance, 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 environment, 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 will 

have deleterious impacts. Commenters pointed to a recent report by the University of Georgia, 
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University of Florida, and Virginia Tech of biodiversity implications of woody biomass 

harvesting in the U.S. southeast which found that without additional protections 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 criteria 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 

convert 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 guidelines 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 demonstrating 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 the 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 carbon 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, commenters 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 

framework 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 when 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 sustainable 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 compliance tool under 

Section 111(d).
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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 

removal 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. Because 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 neutral 

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 emissions 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 

memorandum 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 compared 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 clearly 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 sinks 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 concern 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 CO2

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 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 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. Commenters 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 reductions 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" without 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 forestry" 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 biomass 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 feedstocks." Commenters noted that demonstration would say 

very little, if anything, about the amount of biogenic CO2 emitted by the source or the net effect 
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of those emissions on atmospheric CO2 loading. Commenters stated that consequently, EPA 

cannot meet its obligations 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. Commenters 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." Commenters 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 sources 

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 "sustainably-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 would 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 long-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 emissions 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. Consequently, 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 November 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 that 
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biomass removals in the South more than doubled between 1952 and 2006 and biomass supply 

(i.e. growing-stock volume) 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 CO2

emission performance rate (or mass). Renewable energy and demand-side EE and other nonBSER measures that are tied to a state plan and achieve quantified and verified MWh savings 

may be used to adjust a CO2 emission rate, provided they meet the general and specific eligibility 

requirements for resources used to adjust a CO2 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 could 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-energy.

Response 32: A discussion regarding the use of some biomass feedstocks, including waste-toenergy, 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 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 for 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 

Sources." 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 upon 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. Commenters stated that the IPCC's 

5th Assessment Report recently updated the 100 year global warming potential (GWP) to 34 
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CO2 when climate-carbon feedbacks are included. Commenters added that the selection of the 

time period of GWPs is a policy call, and a shorter 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, and, 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 base 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 state 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, states 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 measurement 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 diversification, 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 

transmission. 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 properly 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 existing 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 have 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 electricity 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 greenhouse gas 

intensity reduction requirements and the state would have fewer "building block 3" compliance 
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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/municipal/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 methane 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 confusing 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 viability 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 sustainable 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 regarding 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 fossil-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 added 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 reduction 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-intensive generating technologies while simultaneously 
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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 population 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 greater 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 perennial 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 feedstocks 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 emission 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 landfill 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-hazardous 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 year, 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 well 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 that the SCC is an 

estimate of the economic damages associated with a small increase in carbon dioxide (CO2) 
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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 other 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-lived 

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 feel 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 utility 

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 potential 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 Municipal 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 solid 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 originate 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, municipal 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 (LFG), livestock manure, and waste water treatment 
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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 generation 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 estimated 

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 from 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 of 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 facilities 

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 environmental 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 Carolina, 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 potential 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 Commission as RPS-eligible using biomethane, and 

California is currently developing new regulations to allow additional sources of biomethane 
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within the state to be sent through the interstate pipeline system and designated for use in power 

plants. Commenters 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.

Response 33: A discussion regarding the use of some biomass feedstocks, including waste-toenergy, 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 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 clarification 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 

generate 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 generation 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 emissions 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 quantification 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 dioxide 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 the 
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Integrated Waste Services Association to provide industry driven 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 biogenic 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 provides 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 incineration 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 rule. The final rule gives states the flexibility, to use zero- and low-emitting resources to 

achieve their CO2 emission performance rate for affected EGUs. Renewable energy and demandside 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 CO2 emission rate, provided they meet the general 

and specific eligibility requirements for resources used to adjust a CO2 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 reduction 
368

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 fuels. 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 for 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 called 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 take 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 further 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 said 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 likely 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 energy 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. 

Commenters 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 said 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 energy 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 beyond 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 forestry 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. 

Court 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 all 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 concluded 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 baseline 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 uses 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 communities 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 and 
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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 wastederived 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, producing 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 of 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 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 CO2 atmospheric contribution of different 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 for energy production.

A discussion of the use of biomass feedstocks and associated biogenic CO2 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-neutral assumption contradicts the scientific consensus on the climate impact of biogenic 
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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.

• The 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 sequestration. 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 biomass 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 benefits.

• 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 application. 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 were credited under a flexible system that allowed 

averaging across the fleet. 
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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 compliance.

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 facilitate 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 negative air quality impacts. Additionally, commenters 

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 messages 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 streams 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 could 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 of 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 

option 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 designating 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 blanket 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 

that 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 footprint 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.
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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 Accounting 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 generation.

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 recognize 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 literature 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 plans.

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 biomass 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 in 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 biomass 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, landfill 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 fully 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 avoid double 
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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 expenditure 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 

unworkable 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 the 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-fired 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 indicates 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 biogenic 

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 consistently 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 the 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 related 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 cause 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 Framework 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. 
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In addition, commenters said, the categorical determination of carbon neutrality for biomassfired 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 Assessing 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 regulated 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 sustainable forestry practices that are beneficial in 

reducing CO2 impacts fossil fuels. Commenters justified the carbon neutral status of biomassfired generation citing the 2011 "Draft Accounting Framework for Biogenic CO2 Emissions 

from Stationary Sources" and 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 

natural 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 support 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 treat waste biomass as carbonneutral, 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 Woodville 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 incentives 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 of 

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 EPA 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 the 
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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 treat 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, represents 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. Commenters 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 playing 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 trees 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 indefensible 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 state 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 if 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.
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Commenters also noted that biomass fuel is not carbon neutral, its emissions can exceed 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 overproduction, 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 tree 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. 

According 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 biomass," 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" because 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 concentrations 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 harvests 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 biomass (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 plants 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”)
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shows that per megawatt-hour, CO2 stack emissions at the biomass plant are about 145% those 

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 results 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. Commenters 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 meanwhile, 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 showing 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 utilityscale 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 for 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 may 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 contemplates 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 relative 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 only agricultural waste products, compliance with 
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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 sequester 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 

unreliable 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 fossil 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 which 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, commenters 

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 the 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 (methane) 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 in 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 in "climate benefits" when compared to 

fossil fuels. 
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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 lawfully 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 plans. 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 emitted (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 the 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 biomass 

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 unsupported 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 carbon 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 between 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 be 
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burned tomorrow and converted into CO2 with no discernible effect on the climate, 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 

contribute 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 per 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 States 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 significant 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 compiled 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 generation 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 mediumtime 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 

positive, 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 only 
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makes a mockery of the so-called scientific review process that EPA employed to devise a 

system for biogenic carbon accounting, but also fundamentally reduces the ability of the GHG 

rule to reduce CO2 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 CO2 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 Framework and an abundance of peer-reviewed science, that 

harvesting and burning forest wood for energy represents a large net source of CO2 emissions

that persists for decades to more than a century. 

Commenters stated that invocation of "sustainable" harvesting 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. 

Commenters 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 for 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 exceed those from alternate fates, meaning that for most 

scenarios, burning these materials adds net CO2 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 determine the net effect of a biomass -burning facility on atmospheric CO2

loading. In fact, the commenters stated that the concept of "sustainable" harvesting is 

(appropriately) not mentioned in the Framework. Commenters provided several figures to 

illustrate 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 emissions 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 contextualize 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 zero 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 allencompassing. 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, or 
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"sustainably harvested" material (an easy claim to make since the term is meaningless).

Commenters stated that a review of current-day biomass sector emissions 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 CO2 in 2012, equivalent to the entire power 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 power 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 urged 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 emissions, 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 bioenergy 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 CO2 atmospheric contribution of different 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 for energy production.

A discussion of the use of biomass feedstocks and associated biogenic CO2 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 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 GHG 
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standards for new fossil fuel-fired 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 fuel 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-neutral 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 2014 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 40 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 biogenic 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 Climate 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 to 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 burn 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 section 

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 as to how biomass 
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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 Id. Commenters recommended 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 appropriate 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 whether 

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 feedstock 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 determined 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, commenters 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 treatment 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 Procedure 
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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 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 CO2 atmospheric contribution of different 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 for energy production.

A discussion of the use of biomass feedstocks and associated biogenic CO2 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 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 biomassfired 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 emissions. 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 

sustainable 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 to 
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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 apparently 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 speculate 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 specifically 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 unreasonable 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 decade. 

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 justifiably 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 types 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 facility. 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 understandable 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, requests 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 is 
388

not clear whether 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 CO2 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 CO2 emission 

rate, provided they meet the general and specific eligibility requirements for resources used to 

adjust a CO2 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 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 CO2 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 sources.

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 

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 CO2 atmospheric contribution of different 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 for energy production.

A discussion of the use of biomass feedstocks and associated biogenic CO2 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/climatechange/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 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 CO2 atmospheric contribution of different 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 for energy production.

A discussion of the use of biomass feedstocks and associated biogenic CO2 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 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 and 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

Commenters 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 zeroemitting 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 discussion 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 believed 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 stated 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 ratebased 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 well 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 sets 

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 CO2 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 the 
391

utility and power market systems, including technological innovations like smart grid, intelligent 

business processes, distributed generation and other elements empowering consumers; costcompetitive 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 investment 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 the 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 demandresponse) 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 much 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 energy. 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 demand, 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 that 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.
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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 

invested in. This final rule supports flexible measures to achieve CO2 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 government 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 "all 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 increases 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 Century 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 anaerobic bioreactors to hydrogen-rich methane biogas, 

carbon-rich actosol organic humic liquid for agriculture use, and HUMASORB, a solid coproduct that can be used to adsorb (i.e., remove) toxic contaminants from wastes and waters. For 

unmineable coal seams, commenters stated that bioconversion occurs in the seam itself and the 

biogas can be recovered gradually. Commenters stated this biotechnology utilizes every 
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component that makes up coal. Commenters stated that even heavy metals, such as mercury and 

arsenic, 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, methane, 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 existing 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 increasing 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. 

Commenters 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 might 

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 development, 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 maintained 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 existing 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 CO2 emission reductions and the increased use of 

zero- and low- emitting generation.

The following are summaries of the specific comments under this comment:
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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 from 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 wells 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 for 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 and 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 

begin 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 lands.

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 CO2 emission performance level for 

affected EGUs or a state CO2 goal, because out-of-sector offsets are not connected to the 

electrical grid and so cannot reliably address stack CO2 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 finalizing as an option under the state measures 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 Revision" attached to a comment, commenters questioned if "beyond the fenceline" 

carbon offsetting for bioenergy is allowable under the GHG rule.
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Commenters stated that extensive use of "beyond the fenceline" mitigation measures for 

reducing greenhouse gas emissions 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 

that 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 increased 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 

emissions at the time it is burned, because essentially all biomass fuels emit more CO2 per unit 

energy generated than all fossil fuels. Thus, the commenters stated that any claim that bioenergy 

emits less CO2 than fossil fuels relies on calculation of net CO2 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 CO2 anyway, or that fuels are sourced from forests or crops that can regrow and 

sequester an equivalent amount of CO2 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 commenters 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 CO2 emissions from burning 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 CO2 in pollution permitting. While the Court's ruling against EPA's deferral of biogenic 

CO2 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 into 
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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 covered 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 CO2 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 sources not regulated by the 

trading program, emissions reductions from offsets would not be counted when 

evaluating CO2 emission performance of affected EGUs, because those reductions 

would not come from those affected EGUs" 

Commenters stated that the prohibition 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 this 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 count 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 CO2

emissions from affected EGUs and meet other state plan requirements. The final rule gives states 

the flexibility to use zero- and low-emitting resources to achieve their CO2 emission performance 

rate. The use of non-affected CHP generating capacity is discussed in preamble section VIII.K. 

The measures discussed in the preamble are representative of those that states may consider in 
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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 under 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 States 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 the 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 contrast 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 

through 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 emissions through lowercost 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 compensation 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 that 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 reductions.

Commenters urged 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 agreed with EPA that electricity transmission 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 extent that new, cost-effective technological advances 

occur, new emission control technologies could also be included. See Id. Commenters said, in 
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addition, once they are appropriately removed from the BSER analysis, the emission reduction 

opportunities identified 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 lowering 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. Commenters 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 industrial CHP units that are excluded from the rule's applicability 

criteria would also be eligible to participate on a voluntary basis. Commenters also urged EPA to 

look beyond the sources identified thus far and explicitly endorse carbon offsets as a viable, lowcost 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, again, that no additional 

obligations are imposed on entities other than affected EGUs.

Commenters believed that EPA's proposal to give affected facilities the flexibility to reduce 

GHG emissions through voluntary partnerships with third parties can serve as 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. Commenters 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 install 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 application 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 substantial carbon reductions in the energy sector. Commenters said with redispatch, 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 dispatched 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 nuclear 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 of 
399

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 

promise 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 would 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 is 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 zeroemitting 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 CO2 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.

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 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 approvable actions to include in state plans.

Comment 50: Also, unlike its proposed rule for new sources, commenters 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 EGUs, 

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 or 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 for 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 allowing the option in 
400

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 goals. Commenters said inclusion of building 

block 3 provides the needed flexibility in states compliance plans and takes advantage of costeffective, readily available RE generation that can also help decrease our reliance on natural gas 

power generation. Commenters 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 excluding 

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 fossil 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 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. A discussion 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 found 

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 consume 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:
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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 with 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 electrical 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 quantities 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 carbon 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 available, 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 wattage 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 waste 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, nonemitting units in the compliance calculation. 

• 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 of 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 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: 

• 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 already 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 power, 

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 CO2 emission rate, provided they meet the general and 

specific eligibility requirements for resources used to adjust a CO2 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, hydroelectric power, and biomass. Preamble 

section VIII.K discuss measures, such as CO2 emission reductions from outside of the power 

sector that may not be used to adjust CO2 emission rates.

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. 

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 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.
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Comment 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 comment:

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 approach. 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. 

Commenters 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 that 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 for 

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 constructed 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 CO2 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 CO2

emissions, commenters found that EPA must place more emphasis on accomplishing CO2
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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 expectations 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 re-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 building 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 that 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 achievable. 

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 comment, 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:
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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 renewable 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 and 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 dispatch 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 companies 

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 today, 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.

Commenters 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 strategies 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 declined 
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dramatically and is often 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 percent 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 prohibitive 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 that 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 resources 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 stated 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 outcome doesn't appear to be in line with incenting 

coal-fired generation to become a smaller contributor to the U.S. power grid.
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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. Commenters 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 

resources 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 organizations 

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 CO2 goals, and instead rely on energy 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 comment:

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 fuel-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 stated 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 "under construction and at 

risk" nuclear capacity is also part of the inventory that the state can count towards compliance 
408

with its state goal." and also "Increasing the amount of nuclear capacity relative to the amount 

that would otherwise be available to operate 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 emissions, 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 know 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 carbon 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 energy 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 necessarily 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 sequestration (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 electricity 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 consumption 

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 avoid or postpone the construction of new 
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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.