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TABLE OF CONTENTS

4.10 Tribe and Territory Goals from SNPR............................................................................... 2

4.10.1 Treatment of U.S. territories and non-contiguous states in goal-setting ...................... 2

4.10.2 Treatment of tribes in goal-setting ................................................................................. 13

4.11 State-specific goal computation comments....................................................................... 34

4.12 Other .................................................................................................................................. 368
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4.10 TRIBE AND TERRITORY GOALS FROM SNPR

Section 4.10 covers public comments related to tribe and territory goals from the Supplemental 

Proposed rulemaking for existing stationary sources in Indian Country and U.S. Territories; 

Multi-Jurisdictional Partnerships. 

4.10.1 Treatment of U.S. territories and non-contiguous states in goal-setting

Section 4.10.1 covers public comments related to the treatment of U.S territories and noncontiguous states in goal-setting.

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: T&T Supplemental - Rework target setting formula - RE BB3

Response 1: The EPA is not including emission performance goals for territories in this final 

rule. See section VII.F. of the preamble for discussion of this issue. However, the EPA has 

revised the target setting formula regarding Building Block 3, please section V.E. of the final 

rule preamble of the CPP for more information about Building Block 3.

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

Commenters stated, in regards to the supplemental proposal, EPA should rework its targetsetting formula so as to reduce dispatch of fossil-fired EGUs in each jurisdiction to the same 

extent that generation is increased from RE (or demand is reduced from energy efficiency 

measures). The commenters said the agency must also ensure that no double-counting of 

renewable credit occurs, and should adopt an avoided MWh approach to determine goal 

compliance, rather than a reduced CO2 approach. The commenters said a key benefit of the 

avoided MWh approach is that it does not require the use of system dispatch and capacity 

expansion models, which can be expensive due to the need to acquire licenses for the proprietary 

software and the expertise needed to properly run the models. The commenters said the burden 

of using these models as part of plan development and compliance assessment would be 

particularly high in the case of tribal and territorial governments, which are likely to have fewer 

specialized staff and financial resources.

Comment 2: T&T Supplemental - The EPA's request for comments on the treatment of low- and 

non-emitting electric generation from Canada, and how imported resources can contribute to 

meeting state goals - the U.S. and Canadian segments of the larger North American grid are 

integrated and interdependent.

Response 2: See section VIII.K. of the final rule preamble of the CPP for the EPA’s response to 

this comment more information about RE measures that occur outside the U.S.
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The following are summaries of the specific public comments under this comment:

Commenters stated, in regards to the supplemental proposal, existing physical linkages between 

the U.S. and Canadian electric power systems are numerous, and are set to continue expanding. 

The commenters said electricity plays an integral role in the vibrant bilateral energy relationship, 

which itself is a pillar of the broader flow of two-way trade that is without compare anywhere in 

the world. The commenters said there are currently more than 35 electric transmission 

interconnections between the Canadian and U.S. power systems, which stretch across the 

international border and together form a highly integrated North American grid. The commenters

said each Canadian province along the U.S. border is electrically interconnected with a 

neighboring U.S. state or states, with many provinces boasting multiple (or in the case of 

Ontario, more than a dozen) international interties. The commenters said U.S.-Canada 

integration is by no means a new phenomenon, with Ontario and New York having established 

their first connection more than 110 years ago.

Commenters stated, in regards to the supplemental proposal, physical linkages between the U.S. 

and Canadian grids have enabled steady growth in a robust continent-wide electricity 

marketplace. The commenters said bilateral trade occurs routinely - and has occurred for decades 

- at a range of points across and beyond the border, with supply fulfilling demand in the most 

efficient, cost-effective manner possible The commenters said such trade enables market 

participants to take advantage of supply diversity across the wider grid, reflected in the very 

different generation mixes in place in either country The commenters said system and market 

integration also underpin economic development on both sides of the border. 

Commenters said historically, electricity exports to the U.S. have represented 5-10% of total 

electric generation in Canada. The commenters said the majority of these exports involve the sale 

of surplus output from provinces with major hydropower resources, such as British Columbia, 

Manitoba and Quebec. The commenters said export volumes from Ontario have also risen more 

recently, making the province the second largest exporter for several years. In 2013, nuclear and 

hydropower comprised over 80% of Ontario's supply. The commenters said New England has 

recently seen an uptick in imports of nuclear energy from New Brunswick following the return to 

service of the Point Lepreau Generating Station in late 2012. 

Commenters stated, in regards to the supplemental proposal, the elements involved in 

maintaining the reliable operation of the interconnected North American grid and managing the 

exchange of electricity across the U.S.-Canada border are extremely complex, requiring the 

support and participation of numerous entities in both countries. The commenters said in recent 

years the bulk of electricity exchanges across the U.S.-Canada border have been executed 

through wholesale markets, with long-term contracts representing less than one-quarter of total 

trading activity. The commenters said these wholesale markets include the real-time and dayahead markets of U.S. ISO/RTO organizations such as the California ISO, Midcontinent 

Independent System Operator ("MISO"), PJM Interconnection, New York ISO ("NYISO") and 

ISO New England ("ISO-NE"). 

Commenters said in the wholesale market context, these deliveries typically occur under one of 

two market structures; first, in power pools administered by ISOs/RTOs, participants transact by 

submitting bids and offers into the pool. The commenters said software is utilized to calculate 
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market clearing prices, including transmission congestion and losses; the other principal market 

model consists of bilateral trading, in which participants negotiate directly with counterparties or 

anonymously via brokers or over trading platforms (e.g. Intercontinental Exchange). 

Commenters said under these market structures, electricity is delivered under the following 

windows/intervals: (i) hourly, meaning delivery occurs at a constant rate over any given hour 

(usually the hour before delivery up until to the day before); (ii) daily, meaning delivery occurs 

at a constant rate over specific periods of a day (usually the day before delivery); and (iii) term, 

meaning delivery occurs over a multi-day period (often monthly, quarterly or yearly, with 

purchases having been made anywhere from the day before to years before). 

Commenters said accordingly, at any given moment in the day, week, month or year, U.S. 

market participants in numerous states and ISO/RTO markets are importing energy from 

Canadian sources, and vice versa. The commenters said interconnections across the North 

American grid help to stabilize minute-to-minute fluctuations by providing a large pool of 

generation and load, which in turn assists in absorbing normal fluctuations and keeping the 

system running smoothly. The commenters said this is all made possible by consistent 

compliance across North America with NERC standards and rules governing participation in 

ISO/RTO and bilateral markets. 

Commenters stated on October 28, EPA issued a supplemental proposed rulemaking which 

highlighted the bi-national implications of the proposed rule and solicited input on, "whether RE 

resources from Canada can be used to contribute to meeting a jurisdiction's goal." The 

commenters firmly believed that imports of non-emitting electricity from Canada can be a tool 

for many states to reduce their dependency on high-GHG emitting electricity generation. The 

commenters said there is significant existing and proposed infrastructure that can bring 

additional clean Canadian power to the United States. The commenters said there are currently 

seven trans-boundary transmission lines proposed that would provide additional clean energy for 

U.S. states to use in their implementation plans. The commenters said various widely respected 

renewable energy credit tracking systems exist that ensure sound accounting of Canadian 

electricity imports. The commenters asked that nothing in the final rule discourage cross-border 

collaboration that leads to cost-effective emissions reductions for the power sector, and that it 

fosters reliability and sustainability in our integrated grid. 

Comment 3: T&T Supplemental - The EPA's request for comments on the treatment of low- and 

non-emitting electric generation from Canada, and how imported resources can contribute to 

meeting state goals - in its final rule, the EPA should appropriately consider, reflect and leverage 

the benefits to U.S. consumers associated with existing and expanded integration of the North 

American Grid.

Response 3: See section VIII.K. of the final rule preamble of the CPP for the EPA’s response to 

this comment more information about RE measures that occur outside the U.S.

The following are summaries of the specific public comments under this comment:
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Commenters stated, in regards to the supplemental proposal, in its final rule, EPA should 

appropriately consider, reflect, and leverage the benefit to U.S. consumers associated with 

existing and expanded integration of the North American grid. The commenters said such an 

approach has the potential to continue facilitating substantial reductions in U.S. GHG emissions -

to which numerous U.S. states and utilities can attest, having already reaped the benefits of a 

lower-emitting power supply through years of purchasing Canadian imports, or having already 

undertaken action to do so. The commenters said as the EPA proceeds with finalizing its 

proposal, the Agency should therefore recognize the emission reductions which have historically 

been realized in the U.S. as a result of the importation of low- and non-emitting generation from 

Canada; likewise, the EPA should not discount or disregard the emission-reduction value of this 

generation by limiting the ability of U.S. states and affected entities to utilize such generation for 

purposes of fulfilling their specific rate-based goals under the 111(d) framework. 

Commenters stated, in regards to the supplemental proposal, failure to appropriately consider, 

reflect and leverage the benefits of existing and expanded U.S.-Canada electric integration in the 

final rule would result in unintended consequences for U.S. entities and would deprive these 

entities of a valuable, proven option for meeting their carbon-reduction goals. 

Commenters said it is imperative that the EPA's final rule neither deliberately nor inadvertently 

deprive U.S. states and affected entities of the carbon-reduction advantages presented by 

integration and trade with Canada. The commenters said this applies both in the context of the 

existing relationship, as well as in the context of transactions and contracts which will be 

executed, and generation and transmission projects which will be developed, subsequent to 

finalization and implementation of the Agency's proposal. The commenters said any undue, 

unnecessary and/or arbitrary foreclosure of the option for affected entities to incorporate lowand non-emitting generation from Canada into their 111(d) strategies will have the opposite 

effect of the types of benefits catalogued above. The commenters said any constraints would 

diminish emission-reduction potential, impair reliability, reduce affordability, and limit 

development prospects for new non-emitting resources in impacted U.S. states; such outcomes 

would be contrary to the stated objectives of the EPA and the President. The commenters 

requested that the EPA avoid any such scenario by ensuring that the benefits associated with 

existing and expanded U.S.-Canada electric integration are appropriately considered, reflected 

and leveraged in the final rule. 

Comment 4: T&T Supplemental - In its final rule, the EPA should specifically state that U.S. 

states will have the flexibility to allow affected entities to utilize the importation of low-and nonemitting electric generation from Canada as a CO2 emission reduction measure.

Response 4: See section VIII.K. of the final rule preamble of the CPP for the EPA’s response to 

this comment more information about RE measures that occur outside the U.S.

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

Commenters stated, in regards to the supplemental proposal, there is precedent under existing 

CAA programs for recognition of the emission-reduction benefits of low- and non-emitting 
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electricity from Canada. The commenters recognized that all components of state 111(d) plans -

including their CO2 emission reduction measures - must be consistent with requirements set 

forth in the CAA and implementing regulations. In turn, the commenters acknowledged that EPA 

requires assurances that the utilization of low- and non-emitting electric generation from Canada 

as a CO2 emission reduction measure must not conflict with relevant authorities and procedures 

under the statute. 

Commenters said while some of the potential approaches under the proposed rule that might 

facilitate the importation of low- and non-emitting Canadian electricity for emission reductions 

are new, there is one such approach that has been used for decades to lower emissions in the U.S. 

The commenters said the Acid Rain Program under Title IV of the CAA, along with NOx budget 

programs under Title I, impose a mass-based emissions compliance obligation on EGUs that is 

measured with continuous emissions monitors. The commenters said under both of these 

programs, when imported Canadian generation reduces the utilization of higher-emitting 

generation from coal-fired EGUs in the United States, it is an automatic compliance measure, 

with no restrictions or additional tracking or verification requirements. 

Commenters said without endorsing the legality or desirability of alternative approaches, the 

commenters asserted that the approaches in the Acid Rain (Title IV) and NOx programs provide 

a strong precedent if states decide to use an EGU, mass-emissions-based approach with a 

compliance obligation for EGUs; in such cases, the treatment of imported electric generation 

from Canada under a state plan should be guided by the precedent of these CAA programs. 

Commenters stated, in regards to the supplemental proposal, states and affected entities should 

have the opportunity to take advantage of U.S.-Canada integration and trade, in view of the 

EPA's assurances that states will be granted maximum flexibility to meet their rate-based goals 

in a manner that reflects their specific circumstances and energy and environmental policy 

objectives. 

Commenters said it is wholly reasonable and appropriate to expect these states to reflect their

integration with Canada and to incorporate recognition of Canadian resources under their own 

programs in the 111(d) plans submitted to the EPA. The commenters strongly asserted that those 

states which wish to pursue this course of action should not be precluded from doing so. The 

commenters said under a host of different public policy and market structure scenarios, the 

importation of non-emitting generation from Canada can serve as a solution that is tailored to 

fulfill the unique environmental and economic needs of a state. The commenters said any 

restrictions on a state's ability in this regard would run counter to the EPA's professed intention 

to allow "each state to maximize the advantages it considers optimal." The commenters said 

what's more, such restrictions would also undermine the "state flexibility principle that is central 

to the EPA's development of this program." 

Commenters applauded the EPA for its commitment to maximizing flexibility for states under its 

planned approach. The commenters said consistent with this signal from the EPA, the Agency 

should facilitate the submittal of state plans which may allow affected entities to benefit from the 

importation of low- and non-emitting electric generation from Canada as one of several 

strategies within a portfolio of GHG-reduction measures. The commenters requested that the 

EPA incorporate language in the preamble to the final rule, to this effect. 
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Comment 5: T&T Supplemental - In the supplemental proposal, the EPA also "requests 

comment on whether areas without affected EGUs may participate in multi-jurisdictional plans." 

The EPA should provide all States and affected EGUs opportunity to identify and incorporate 

out-of-state or international GHG reduction projects for implementation and compliance 

purposes 

Response 5: See section VIII.K. of the final rule preamble of the CPP for the EPA’s response to 

this comment more information about RE measures that occur outside the U.S.

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

Commenters stated in the supplemental proposal, EPA "requests comment on whether areas 

without affected EGUs may participate in multi-jurisdictional plans." The commenters said EPA 

also solicits comment "on all aspects of the treatment of RE, demand-side energy efficiency, and 

other new low- or non-emitting electricity generation across international boundaries in a CAA 

section 111(d) plan, considering the components for approvable plans described in the June 18, 

2014, proposal, including any mechanisms that could be used to ensure that the low or nonemitting generation was in fact offsetting fossil-fuel-fired generation in the jurisdiction that 

would use it to meet its goal." The commenters said while a beyond the fence line approach to 

BSER is unlawful, States and affected EGUs should be given flexibility to allow third parties to 

participate voluntarily at the implementation and compliance stages to the extent that they can 

reduce GHG emissions in a more cost-effective manner than fossil fuel-fired EGUs. The 

commenters agreed that CO2 reduction projects in areas without affected EGUs or in foreign 

countries have the potential to provide cost-effective opportunities to reduce GHG emissions and 

should be available to States, territories, Indian tribes, and affected EGUs-on a voluntary basis 

only-to comply with emission reduction goals established under Section 111(d). The commenters

said however, there is no basis for limiting their applicability to States that participate in multiState plans. The commenters said EPA should provide all States and affected EGUs with equal 

opportunities to identify and incorporate out-of-State or international GHG reduction projects for 

implementation and compliance purposes in the same manner as projects located in the same 

State.

Comment 6: T&T Supplemental - Treatment of renewable energy across international 

boundaries

Response 6: See section VIII.K. of the final rule preamble of the CPP for the EPA’s response to 

this comment more information about RE measures that occur outside the U.S.

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

Commenters stated, in regards to the supplemental proposal, imported renewable energy across 

international boundaries has the potential to reduce in-state emissions from CPP affected sources 

and should be able to receive credit towards a state's compliance under either a mass-based or 

rate-based system. The commenters said imported renewable energy from Quebec is especially 

likely to reduce emissions from affected sources in New York in the same manner as in-state 
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renewable generation; therefore, the final CPP rule should treat imported renewable generation 

that has these characteristics the same as in-state generation. 

Comment 7: T&T Supplemental - Puerto Rico

Response 7: The EPA is not including emission performance goals for territories in this final 

rule. See section VII.F. of the final rule preamble of the CPP for discussion of this issue. 

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

Commenters expressed dismay at the omission of Puerto Rico from the goals list.

Commenters stated, in regards to the supplemental proposal, EPA should reconsider its proposal 

to reduce CO2 emissions by shifting production from AESPR to the island's NGCC plant, in 

view of the unique situation presented by AESPR's long-term contract to supply power to 

PREPA under the Power Purchase Agreement (PPA). 

Commenters urged EPA to revise its supplemental proposal because it is the wrong public policy 

for Puerto Rico. The commenters said Section 111(d) was intended to be a flexible program that 

can be tailored to the specific circumstances of each state or territory through consideration of 

unique factors specific to individual sources or groups of sources. See 42 U.S.C. section 7411(d) 

(1). The commenters said Puerto Rico is in a unique situation that differs from every state to be 

covered by the ESPS - it has only one coal-fired power plant and that plant operates under the 

PPA. The commenters said EPA's proposal, however, would seek to disrupt the settled, longterm contractual expectations of the PPA - and effectively strand a significant portion of Puerto 

Rico's investment in AESPR. The commenters said EPA would do so by requiring PREPA by 

2020 to reduce the electricity it would otherwise buy from AESPR by approximately 17.5%, and 

to shift the dispatch of 17.5% or more of the electricity historically generated by AESPR to 

EcoElectrica, the island's natural gas combined cycle ("NGCC"). The commenters said EPA 

assumes this can be accomplished as part of an overall increase in dispatch of the NGCC 

(increasing the capacity factor from 37% to 70%). The commenters said regardless of whether or 

not shifting dispatch to gas-fired generating units could work in the traditional state regulatory 

context, this approach is not sensible and could not work in Puerto Rico, as it would impose 

significant new wasteful costs on PREPA and the people of Puerto Rico. 

Commenters stated the PPA requires PREPA to pay AESPR each month a capacity payment for 

dependable capacity made available and an energy payment for the energy actually 

delivered. The commenters said thus, so long as AESPR continues to maintain its units to ensure 

it has the capacity to provide electricity to PREPA, PREPA is contractually obligated to make 

the monthly capacity payment for the life of the PPA. The commenters said this type of 

obligation is an essential element of any power purchase agreement and the PPA in Puerto Rico 

is no exception; however, starting in 2020, EPA's proposal would require PREPA not to take 

approximately 17.5% of the dependable capacity that AESPR otherwise would use to produce 

electricity for PREPA. The commenters said thus, by contract, from 2020 through 2027, Puerto 

Rico would be obligated to pay many millions of dollars each month in capacity payments to 
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AESPR for energy that EPA's proposal would require PREPA not to purchase. The commenters

said that would be the nonsensical result of arbitrary and capricious agency action. 

Commenters stated moreover, reducing the dispatch of the plant has additional cost implications 

under the PPA. The commenters said as a baseload plant, AESPR operates most efficiently at 

higher capacity factors; hence, if the plant is dispatched at lower rates and is forced to cycle on 

and off, there will be higher maintenance costs, and the PPA requires PREPA to pay those costs 

in the form of a higher variable cost component of the monthly energy payment. The 

commenters said those additional costs would also have to be paid by PREPA, if EPA's proposal 

to shift the dispatching to the NGCC from AESPR were adopted. 

Commenters added these costs would be compounded by shifting a significant share of the 

electricity from AESPR, the lowest cost provider, to the NGCC. The commenters said 

EcoElectrica will cost PREPA approximately $30/MWh more than AESPR to provide the same 

electricity. The commenters said assuming, as EPA proposes, that PREPA would replace 

approximately 600,000 megawatt hours of electricity from AESPR with electricity from EcoElectrica's NGCC, Puerto Rico will face an additional $18 million in annual energy costs. The 

commenters said these costs do not include the additional costs (e.g., brownouts, etc.) that could 

occur if PREPA were foreclosed from relying fully on AESPR's reliable, coal-fired power. The 

commenters said as the only coal-fired power generator, AESPR provides a reliable, stable 

source of base load power. The commenters said a basket of energy resources provides the best, 

most reliable source of energy, and concerns have been raised by energy regulators about putting 

too much faith in gas-fired power to the exclusion of coal fired generation. The commenters said 

moreover, these are costs that Puerto Rico can ill-afford to assume; while the United States has 

seen a modest economic recovery, the island remains deeply mired in recession with an 

unemployment rate of 14%, more than double the rate on the mainland United States. 

Commenters urged EPA to take into account the existing 25-year PPA in framing any emissions 

reduction program in Puerto Rico. The commenters urged EPA to extend the deadline for Puerto 

Rico to submit an implementation plan until at least four years after EPA issues a final rule and 

to eliminate entirely the 2020 interim compliance period. The commenters said by eliminating 

the interim deadline and focusing solely on the final 2030 compliance date, EPA would not 

conflict with the contractual requirements established by the existing PPA between AESPR and 

PREPA. The commenters said the initial compliance deadline of 2020 would provide far too 

little time for Puerto Rico to develop a regulatory program to administer the program and for 

PREPA, AESPR and others to take the kinds of steps contemplated. The commenters said 

alternatively, at a minimum, the commenters urged EPA to conform any final rule to the 

parameters established by the existing PPA by providing a full CO2 emissions allowance 

allocation to AESPR for the term of the PPA. 

Regarding the tribal and territories supplementary rule, commenters stated that the Supplemental 

Proposal does not consider the EGUs current operation reduction as an alternative to building 

blocks 1 and 2, which will result in substantially higher emission reductions when compared to 

the Puerto Rico's opportunities with EPA's proposed requirements for building blocks 1 and 2. 

The commenters stated that in Puerto Rico, some of their EGUs affected by the Proposal will be 
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limited in their operation, beginning in April 16 2015. The commenters stated that this results 

from their strategy determination to comply with the Mercury and Air Taxies Standard (National 

Emission Standards for Hazardous Air Pollutants from Coal- and Oil-Fired Electric Utility Steam 

Generating Units and Standards of Performance for Fossil-Fuel-Fired Electric Utility, IndustrialCommercial-Institutional, and Small Industrial-Commercial-Institutional Steam Generating 

Units, Final Rule. The commenters stated that they believe that EPA's emissions guidelines 

should provide full compliance credit for the avoided emissions that result from the retirement or 

operation limitation of existing EGUs prior to the interim goal compliance deadline.

Commenters, operators of electric utility company on Puerto Rico, stated that building block 1 

requirements for oil-fired EGUs on Puerto Rico should not be included in BSER determinations 

for Puerto Rico because the utility has already completed these heat-rate improvement projects 

on most of their units.

Commenters stated that to achieve the contemplated heat rate improvements, the Supplemental 

Proposal is effectively directing Puerto Rico to require them to redevelop a new plant -- or 

certainly to make wholesale equipment replacements and upgrades that would be prohibitively 

expensive. See 42 U.S.C. Para 7411(a) (1) (requiring EPA to "tak[e] into account the cost of 

achieving such reduction" when establishing BSER). Commenters stated that for example, they 

would anticipate that to actually materially improve heat rate at their facility, the plant would 

have to completely retrofit the turbines (with a "dense pack" model), install additional cells for 

the cooling tower, or make other wholesale replacements, which would require replacing 

equipment that is only 12 years old. Commenters stated that would entail investments of literally 

hundreds of millions of dollars - funds that are not available to the facility, costs that likely could 

not be absorbed by an already financially strapped PREPA involved in a multi-billion 

restructuring, and costs that an already overburdened Puerto Rico consumer cannot afford to 

bear. Commenters stated that moreover, on top of those costs, their organization, PREPA, and/or 

the consumer would have to bear the burden of more expensive replacement power while the 

their facility is taken offline and redeveloped. Commenters stated that further, EPA has made this 

proposal, without giving any consideration as to whether these measures would be allowed under 

the PPA - or who would bear the costs. Commenters stated that however, the PPA, which is the 

contract at the center of the development of the project, must be considered when establishing 

standards of performance for Puerto Rico. Commenters stated that an $800 million independent 

power project - a critical boost to the economy of Puerto Rico - could not have been built without 

independent financing. Commenters stated that independent financing, in turn, could only be 

secured by a long term power purchase agreement that would guarantee a stream of agreed upon 

future payments by PREPA, in exchange for their facility providing a reliable source of energy to 

PREPA over the 25- year term of the PPA. Commenters stated that agreed upon in 1994 and 

amended in 1999, the PPA does not expire until 2027 but that however, the PPA did not 

contemplate that they would be redeveloping their facility during the life of the PPA. 

Commenters stated that the PPA requires PREPA to pay them each month a capacity payment 

for dependable capacity made available by the facility (as measured by the equivalent 

availability of the unit "EAF")) and an energy payment for the electricity actually delivered. 

Commenters stated that these payments are absolutely essential to sustain their facility as they 

are their only source of funds. Without PREPA's payments, the plant could not operate. 

Commenters stated that however, to receive the capacity payments, they must maintain the units 

at a high level of availability. Commenters stated that to ensure they maintain a high EAF, there 
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are penalties imposed on them (in the form of reduced payments) if they do not maintain a 12-

month rolling average EAF of at least 90%, with the penalties increasing as the EAF decreases. 

At an EAF of less than 70%, the plant would effectively be in default. Commenters stated that 

the PPA did allow some time for major maintenance that would not impact the payments - but 

those hours are very limited and are staggered (no more frequent than every 3 years) throughout 

the life of the project to provide for the maintenance (e.g., planned normal turbine maintenance) 

that was anticipated. Commenters stated that thus, unless the costs were paid by PREPA under 

the PPA, they cannot simply take a unit down for 3 or 6 or 12 months or more in order to build a 

new cooling tower or replace their turbines or undertake other major capital work to redevelop 

their facility, as to do so would reduce the EAF of the plant below 70%. Commenters stated that 

even just a 60-day unplanned outage, unless covered under the PPA, could cost them some $13.5 

million in losses.

Comment 8: T&T Supplemental - Guam

Response 8: The EPA is not including emission performance goals for territories in this final 

rule. See section VII.F. of the final rule preamble of the CPP for discussion of this issue.

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

Commenters said EPA's supplemental proposal applies Block 2 dispatch reductions to Puerto 

Rico but not to Guam, since the former has excess NGCC capacity but the latter does not. The 

commenters said as EPA has noted in its supporting materials, it is technically feasible to operate 

the EcoElectrica NGCC plant in Penuelas at a 70 percent utilization rate (in comparison to its 

existing utilization rate of 37 percent), and that the territory's steam EGUs can be expected to 

curtail dispatch in equal measure. The commenters said they lack information to determine 

whether Guam has any options to reduce the dispatch of steam EGUs on the basis of excess 

NGCC capacity, and urge EPA to evaluate this possibility.

Commenters stated, in regards to the supplemental proposal, due to its location in the middle of 

the Pacific Ocean, the Guam Power Authority's (GPA) system is not connected with the grids on 

the other Islands and there are no connections with continental U.S. sources of power. The 

commenters said there are no other power producers on the island of Guam with the exception of 

emergency generators and GPA administers the grid. The commenters said due to its isolated 

nature, GPA's system differs from electric generating systems in the contiguous 48 states in a 

number of significant respects; these include: 

1. limited fuel choices - there is no coal, natural gas or liquefied natural gas available on 

Guam; 

2. Increased need for on-island generation resources must be met by GPA to maintain 

system reliability; 

3. Limited economies of scale - to maintain reliability, the system requires multiple smaller 

generation units as opposed to a few larger units; 
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4. Limited flexibility for scheduling overhauls and other extended planned maintenance 

outages; 

5. Different operational regimes for the GPA units as compared to those in interconnected 

grids; and 

6. Among the highest electric rates in the country. 

Commenters said for these reasons, the compliance requirements set forth in the Proposed Rule 

limit the flexibility of GPA (and other island utilities) in ways far more pronounced 

than counterparts located in the continental U.S; however, in 2012, GPA commenced resource 

implementation plans designed to address, among others, compliance with current and upcoming 

environmental regulations. The commenters said these plans once implemented may allow GPA 

to comply with the proposed rule. The commenters said GPA has already begun its resource 

implementation plan to address resource needs that meet environmental regulatory requirements. 

The commenters said once these plans push through, GPA will be able to comply with the rule; 

however, assistance and collaboration with USEPA is requested, for the development and timing 

of State Implementation Plan. 

Comment 9: T&T Supplemental - U.S. Virgin Islands

Response 9: The EPA is not including emission performance goals for territories in this final 

rule. See section VII.F. of the final rule preamble of the CPP for discussion of this issue.

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

Commenters stated, in regards to the supplemental proposal, EPA notes that the two units in the 

U.S. Virgin Islands that would otherwise be subject to the rule - the oil-fired steam EGU in 

Krum Bay and the coal-fired St. Croix Renaissance - have ceased operation and are presumably 

retired. The commenters said accordingly, EPA declined to regulate these units and did not cover 

the U.S. Virgin Islands under the supplemental proposal. While the commenters agreed that 

retired plants should not be included in the goal-setting process, EPA did not clarify whether 

these two units retain operating permits. The commenters said EPA must require these units to 

surrender any operating permits if they wish to remain free from regulation under the 

supplemental proposal. The commenters said if they are undergoing repowering projects, they 

must be covered under the agency's 111(b) standards. The commenters said there is one oil-fired 

combustion turbine at Krum Bay that is not currently classified as a regulated EGU under the 

CPP; EPA must ensure that all fossil fuel-fired EGUs that supply electricity to the grid, including 

the Krum Bay oil CT, are covered under both the 111(b) and 111(d) rules, as well as the 

supplemental proposal.

Comment 10: Electric transmission infrastructure permitting, review, and consultation by the 

Federal government on both Federal and non-Federal lands.
13

Response 10: See sections V.D and V.E of the final rule preamble of the CPP for discussion of 

this issue.

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

Commenters stated in 2009, nine federal agencies, led by the U.S. Department of Energy, 

executed a joint Memorandum of Understanding (MOU) in an effort to improve coordination in 

working through the federal approvals required for energy infrastructure projects.[Memorandum 

of Understanding Regarding Coordination in Federal Agency Review of Electric Transmission 

Facilities on Federal Land (Oct. 23, 2009)] The commenters said the White House Council on 

Environmental Quality (CEQ) has moved a step further by establishing the Rapid Response 

Team for Transmission (RRTT); as stated by CEQ, the "RRTT aims to improve the overall 

quality and timeliness of electric transmission infrastructure permitting, review, and consultation 

by the Federal government on both Federal and non-Federal lands..." The commenters said the 

initial focus of the RRTT has been on seven pilot projects; five of those projects are located in 

the Western U.S., including one project that crosses portions of Arizona and New Mexico, the 

SunZia Southwest Transmission Project. The commenters said the lead federal agency 

overseeing the necessary approvals for this project is the U.S. Department of Interior's Bureau of 

Land Management (BLM); cooperating agencies participating in project permitting include: 

Arizona Department of Transportation, Arizona State Land Department, Arizona Game and Fish 

Department, National Park Service, New Mexico Spaceport Authority, New Mexico State Land 

Office, U.S. Army Corps of Engineers, Holloman Air Force Base, Ft. Bliss (U.S. Army), White 

Sands Missile Range (U.S. Army), Ft. Huachuca (U.S. Army), U.S. Fish and Wildlife Service, 

the Department of Defense Siting Clearinghouse, and the Bureau of Indian Affairs. The 

commenters said the purpose of the SunZia Project is to transport electricity generated by new 

power generation resources to western power markets and load centers. The commenters said the 

project consists of two 500 kilovolt transmission lines originating at a new substation in Lincoln 

County in the vicinity of Corona, New Mexico, and terminating at the existing Pinal Central 

Substation in Pinal County near Coolidge, Arizona, which is operated by SRP. 

Commenters stated work related to obtaining project approvals began in September 2008 when 

project proponents filed an application for a right-of-way across BLM lands, but approval has 

not yet been provided. The commenters said at this time, it is projected that federal permitting 

will be complete in 2015, more than 6 years after it was initiated. The commenters said project 

construction is expected to take an additional 3 years. The commenters said none of the five 

western projects under review of the RRTT has secured the approvals necessary to complete 

project construction. The commenters said although EPA might express optimism that approvals 

for the new gas pipeline and electric transmission projects necessitated by the Proposed Rule will 

take less time than the SunZia Project, the Agency cannot guarantee this fact, particularly given 

the high probability any project undertaken in Arizona will require multiple federal and state 

approvals before it can proceed. 

4.10.2 Treatment of tribes in goal-setting
14

Section 4.10.2 covers public comments related to the treatment of tribes in goal-setting.

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: Tribal should be subject to CPP

Response 1: The EPA has established goals for the three areas of Indian Country with affected 

EGUs. For the EPA’s response to this comment, see sections VI and VII of the final rule 

preamble of the CPP and the CO2 Emission Performance Rate and Goal Computation TSD for 

CPP Final Rule supporting the final CPP.

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

Commenters stated if the federal government allows the delay of clean power and waive policy 

for Navajo, you will put the U.S. at the same level as China where the is no policy and regulation 

to control pollution level within and surrounding the Navajo there are several national state, and 

tribal parks that draws millions of tourists from all over the world, Grand Canyon, Mylet Valley, 

Canyon at the Shay, Navajo National Park, Rainbow Bridge and many others are located near 

and on the Navajo Reservation. The commenters said local government and businesses depend 

on these parks while EPA's recent decision for NGS and bark control is not protecting the 

Navajo. The commenters said while the pollution hays is being addressed for national park, it is 

delayed on Navajo; this is simply another environmental injustice that our people and our air is 

not safeguarded. The commenters said the Navajo nation should be pursuing alternative energy 

with full support under federal government instead of allowing the Navajo to go in the opposite 

direction.

Commenters stated right now the Navajo nation is surrounded by at least five coal-fired power 

plants, two of which are located on the Navajo nation, one in Arizona and one in New Mexico. 

The commenters were concerned when an article was released stating that the power plants 

located in Indian country were being delayed from the proposed rule and that tribes will have the 

opportunity to come up with their own cleanup plans. The commenters understand there are 

multi-jurisdictional issues with tribes and states especially for the Navajo nation, but thinks this 

is unacceptable. The commenters urged the Environmental Protection Agency to enforce the 

clean power plan for all power plants in the U.S. including the power plants located in Indian 

country.

Commenters expressed support for the President's Climate Action Plan for the country and 

expressed concern for the EPA's plan to accept an alternative to the Navajo Nation, which is a 

deviation from the rest of the country's for clean air. 

Commenters also stated his understanding that President Shelly's plan will change only by five to 

six percent from what it has been the past 40 years and that this percentage is extremely small 

compared to EPA's recommendation at 24, Arizona at 52 percent, and New Mexico and 

Colorado at 34 percent. The commenters stated that this plan certainly does not address the 

climate change in the Southwest United States.
15

Commenters stated that under the current percentage operation will continue at the same rate for 

the life of the power plants and the coal mine and this translates to continued use of water at the 

same rate, either from the River or the in aquifers, and furthermore, Peabody is pumping pristine 

water from Black Mesa, however this water is not used by Navajo residents, businesses, schools, 

or hospital.

Commenters asked why there is no hearing or hearings in the regions where these power plants 

actually exist and the communities who are actually impacted by those power plants. 

Commenters stated that proposed reductions for the tribe and these power plants is simply not 

enough to address the impacts of climate change and also not enough to reduce the other 

pollution that comes from these power plants outside of carbon dioxide, like methane and sulfur 

dioxides and nitrous oxides, which impact people's health and also impacts the water that are

used to keep these operations going, and also impacts our Navajo Nation economy.

Commenters stated it's just too lax, it's too unambitious. 

Commenters stated that the carbon final goal for Navajo Nation is pretty much based after 

TWIG, which is interrupt, just shut down one unit and assume that will take care of all the 

problems, mainly dropping the carbon emissions by 30, or at least a third.

Commenters stated that the TWIG decision is now under petition for review. Commenters stated 

that TAR and cooperation with the EPA and the Navajo Nation, TAR is only for eligible tribes 

and as part of the lease agreement with NGS and SRP, the Navajo Nation waived a lot of 

regulations on the operation of NGS so that formation of TWIG is actually a form of regulation

derived from TAR, Tribal Authority Rule. 

Commenters stated that there is amendment of Navajo Nation council for the Navajo Nation to 

cooperate with SRP and environmental and emission controls, but that amendment says this 

amendment does not take effect until it's signed off by the Secretary of Interior a little later, so 

that amendment is really no good and TWIG is actually illegal.

Commenters requested that EPA go back to the drawing boards and find a way to get around the 

323 grant and lease agreement with SRP and the tribe so that the Navajo Nation can be TAR 

eligible. 

Commenters expressed concern that EPA was considering leaving the Four Corners Power Plant 

out of the Clean Power Plan and about the supplemental ruling for the Dine land based power 

plants. Commenters stated that four to six percent suggested level for the Four Corners Power 

Plant is not enough to ensure healing, nor will it create an impact on any level.

Commenters appreciated EPA's effort to gather public input on this really important rule. 

Commenters supported the general approach that EPA used to develop carbon dioxide emission 

standards for existing fossil fuel fire power plants located on tribal land and agreed with EPA's 

decision to maintain the same analytical framework that was first used in the June 2014 proposal, 

and apply the four building blocks in a manner that's consistent with the proposed state emission 

goals. 
16

Commenters were pleased that the participants in NGS and Four Corners will not be required to 

take any additional measures to meet the prescribed emission goals and appreciated EPA's 

recognition that substantial carbon dioxide emission reductions have been or will be achieved at 

Four Corners and NGS through actions taken to comply with the regional Haze Rules. 

Commenters appreciated that EPA has structured the proposal to provide credit for those carbon 

dioxide reductions.

Commenters stated that for 15 years of her life she has lived within 70 miles of two of the worst 

power plants in the country, the Navajo Generating Station and the Four Corners Power Plant 

and that both of these power plants are located on the Navajo Nation. 

The commenters acknowledged that these power plants have provided jobs and revenue for the 

Navajo Nation, but also knows these power plants are old and they do not directly provide 

electricity for the people residing on the Navajo Nation because the power is owned by nonNavajo utility companies and is delivered to Southern Arizona and Southern New Mexico, and 

from there the Navajo tribal utility authority purchases the power back from these companies, 

and in order to provide electricity to its Navajo customers residing on the Navajo Nation.

Commenters stated that in addition the Navajo Nation has zero percent ownership of these plants 

and billions of gallons of water has been pumped from Lake Powell and the San Juan River to 

cool the units down, and the emissions from these power plants have affected the environment 

and the people, both on and off the reservation. Commenters stated that emissions from these 

power plants do not stay on the Navajo Nation. They travel to nearby towns, national parks, and 

waterways. 

Commenters stated that it doesn't make sense that the power plants on Indian Country were 

exempt from this strong Clean Power Plan proposed by the rest of the country, and now a weak 

supplemental proposal has been issued by EPA. Commenters thanked EPA for proposing the 

Clean Power Plan and its supplemental proposal to help curb the number one source of carbon 

pollution on a national level and within Indian Country, however, the supplemental proposal 

only reduces emissions by at least four percent for both power plants by 2030, which does not 

provide equal protections as proposed for the rest of Arizona and New Mexico. Commenters

questioned how communities and future generations benefit from just a four percent reduction, 

why communities continue to suffer from the climate disruption for many years already and that 

they deserve the same treatment as the rest of the country.

Commenters stated that NGS and the Four Corners Power Plant have shut down at least one of 

their units to reduce their emissions, but that should not excuse them from reducing even more 

emissions for the next 15 years and they should transition at least 30 percent of their plants to 

cleaner energy by 2030.

Comment 2: T&T Supplemental – The EPA should work closely and collaborate with Tribes to 

develop emission goals and compliance plan and provide needed flexibility

Response 2: See section II.I. of the final rule preamble of the CPP for the EPA’s response to this 

comment.
17

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

Commenters stated, in regards to the supplemental proposal, EPA should consult with the 

Navajo Nation to establish appropriate and mutually acceptable CO2 emission goals for 

promulgation in the final rule. The commenters said given the timing challenges associated with 

the proposed compliance dates, and the complexities raised by the covenants not to regulate 

contained in the NGS and FCPP leases, the commenters asserted that the most productive and 

efficient path forward is for the EPA to take the lead role in the development of emission goals 

and a compliance plan that meets the unique needs and objectives of the Navajo Nation. The 

commenters encouraged EPA to work closely and collaboratively with the Navajo Nation to 

ensure that the emission goals and compliance plan are acceptable to the Navajo Nation and 

provide the flexibility needed by the Nation to pursue economic development opportunities 

within the Nation. 

Commenters stated that it's about health, wellbeing, jobs, and trying to transition off fossil fuels 

and the four building blocks that you have, they're in a good direction. 

Commenters stated that to hold the tribe accountable to make a decision on, transitioning to, 

whether its natural gas or renewable energy, the tribe wants to have input on that because its 

going to occur on their lands and that transition needs to be from the ground up.

Comment 3: General comments before supplemental came out

Response 3: See sections II.I, VI and VII of the final rule preamble of the CPP and the CO2

Emission Performance Rate and Goal Computation TSD for CPP Final Rule supporting the final 

CPP for the EPA’s response to this comment.

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

Commenters stated affected Western states want to work with EPA and the tribes to understand 

how the 111(d) compliance plans for tribal sources will work with state compliance plans. The 

commenters asked will EPA, on behalf of the tribes, develop 111(d) plans for tribal sources in 

time for them to be coordinated with state plans. The commenters looked forward to reviewing 

EPA's supplemental proposal addressing tribal sources, and expects EPA to finalize the tribal 

section of 111(d) simultaneously with the rest of the rule.

Comment 4: Tribal lands should be treated as additional state

Response 4: The EPA has established goals for the three areas of Indian Country with affected 

EGUs.For the EPA’s response to this comment, see sections VI and VII of the final rule 

preamble of the CPP and the CO2 Emission Performance Rate and Goal Computation TSD for 

CPP Final Rule supporting the final CPP.

The following are summaries of the specific public comments under this comment:
18

Commenters stated tribal lands should be treated as an additional state, as EPA wishes to receive 

comment on this. The commenters said it will be wrong to have all the tribes be generalized into 

the state they are living in and have them accept the state's rules. The commenters said EPA must 

consider the importance of letting the tribes have their own flexibility and freedom as a state 

would under this proposal. The commenters said there are four potentially affected power plants 

within the tribal lands and by not offering them their own liberty, it may cause an outrage from 

the members, assuming they would want to set their own regulations. The commenters said EPA 

should not interfere with the culture and set borders for the Indian country.

Commenters stated in the same manner as a state, carbon dioxide emission goals should be 

formed by the EPA. The commenters said the Indian country would simply be an additional 

category within the proposal's documents. The commenters added EPA should strongly focus 

their efforts to convince them to create more renewable energy within the tribal lands. The 

commenters said it will take the whole country to produce the necessary carbon dioxide emission 

levels and this undeniably includes the tribe nation as well. The commenters said having the 

Indian tribe members create their rules to reach the established carbon generation goals, it will 

provide many benefits for both sides.

Comment 5: Tribal generation sources are few in number but significant in size – future 

operations important to planning

Response 5: See section VIII 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 the Southwestern U.S. is served by a number of large tribal generation 

sources that are not subject to state jurisdiction. The commenters said these tribal sources in the 

West are few in number, but significant in size. The commenters said in 2013, three tribal, coalfired power plants were responsible for 11% of CO2 emissions from the electricity sector in the 

11 states that comprise the Western grid. The commenters said some of these tribal sources are 

scheduled for full or partial shutdown over the next 15 years. The commenters said 

understanding how these tribal sources will operate in the future is important to electricity 

planning in the Southwest. 

Comment 6: Emission reductions credits

Response 6: See section VIII 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, in response to the supplemental proposal, that they support EPA's 

recognition that significant reductions in CO2 emissions have been made at FCPP, and will be 
19

made at NGS as a result of compliance with other regulatory requirements. The commenters 

supported EPA's decision to structure the proposal such that the emission reductions achieved at 

FCPP and NGS can generate credits potentially for use in other jurisdictional compliance plans 

or for the economic benefit of the Navajo Nation. The commenters said the allocation and use of 

any excess credits should be worked out between the owners of NGS and FCPP and the Navajo 

Nation.

Commenters stated, in response to the supplemental proposal, in a letter dated September 18, 

2014, the Navajo Nation requested that EPA grant the Navajo Nation ownership of any available 

carbon credits associated with NGS. The commenters said EPA should ensure that carbon 

credits, to the extent they will be available, are allocated in a manner that avoids any increase in 

the cost of NGS power.

Comment 7: T&T Supplemental - Building blocks application on plants within Indian territory

Response 7: For the EPA’s response to this comment, see sections V.A., VI, and VII of the final 

rule preamble of the CPP and the CO2 Emission Performance Rate and Goal Computation TSD 

for CPP Final Rule.

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

Four Corners

Commenters stated EPA's notice regarding Indian Country proposes to require a six percent heat 

rate improvement at the Four Corners Power Plan without evaluating whether that plant is 

capable of meeting that standard, which EPA developed based solely on nationwide averages. 

The commenters added EPA's notice proposes to require demand side efficiency improvements 

in one of the poorest regions of the country that only consumes a minimal amount of electricity; 

however, the retirement of Units 1 through 3 appear sufficient to meet these requirements. 

Commenters stated if EPA seeks to impose a source-specific efficiency improvement 

requirement on an individual plant, EPA must determine whether that standard is achievable at 

that plant. The commenters added EPA should re-evaluate whether asking one of the poorest 

regions of the country to invest significant capital in energy efficiency projects represents good 

public policy. The commenters said EPA should confirm that the retirement of Units 1 through 3 

will satisfy the Clean Power Plan requirements for the Four Corners Power Plan. 

Commenters stated on November 4, 2014, EPA published a proposal for regulating power plants 

located in Indian Country under the Section 111(d) program. The commenters said that proposal 

covers only a few facilities, one of which -the Four Corners Power Plant, of which Public 

Service Company of New Mexico (PNM) owns a 13 percent share- is geographically located 

within the borders of New Mexico, but on lands that are under the jurisdiction of the Navajo 

Nation. The commenters said for the Four Corners Power Plant, EPA proposes to apply only two 

of its four building blocks-building block 1, to require a six percent heat rate improvement, and 

building block 4, to require a small improvement in demand-side energy efficiency. The 

commenters said both of these requirements appear unreasonable:
20

1. The commenters said as EPA has implicitly admitted in its related proposal for Section 

111 requirements for modified and reconstructed units, an individual power plant may 

not be able to achieve a six percent heat rate improvement because the analysis 

underlying EPA's six percent assumption is based on a fleet-wide average that may not be 

appropriate for a single plant; yet EPA has proposed a six percent improvement for the 

Four Corners Power Plant without making any attempt to determine whether that level of 

improvement is achievable at the specific units that comprise the Four Corners Power 

Plant. 

2. The commenters were concerned that EPA would attempt to force electricity consumers 

within the Navajo Nation to spend additional capital on projects designed to reduce 

electricity consumption. The commenters said the Navajo Nation is one of the poorest 

areas in the country, and therefore one of the least likely to have the means available for 

improving energy efficiency. In fact, the commenters understand that many citizens of 

the Navajo Nation do not even have the means to purchase enough electricity to perform 

basic functions that individuals living in more affluent portions of the country take for 

granted. 

Commenters said despite the unreasonable application of building blocks 1 and 4 to the Four 

Corners Power Plan, EPA appears to have addressed the retirements of Units 1 through 3 at the 

facility in a manner consistent with the retirements expected a San Juan (one of PNM facilities). 

The commenters said EPA included those retired units in establishing the emission reduction 

goals, thus allowing the retirement of those units to count towards compliance in future 

compliance demonstrations. The commenters said given the significant reduction associated with 

the retirement of three coal-fired units, it appears that those units will provide sufficient 

compliance credit to allow the facility to comply with the Clean Power Plan proposed for Indian 

Country. As such, the commenters supported the goal that EPA has established for the facility, 

and encourages EPA to include an express statement confirming this understanding in its 

response to this comment. 

Fort Mojave

Commenters stated the rate-based emission performance goals proposed by EPA for Fort Mojave 

are inflexible and do not cohere with the overall framework of the Clean Power Plan; nor do they 

reflect the "unique conditions" for an area of Indian country that has only one facility in its 

jurisdiction and, accordingly, little to no opportunity to achieve reductions through any of the 

Building Blocks. 

Commenters stated EPA's final rate-based goal for Fort Mojave is 855 lb/MWh; this goal is 

much lower than South Point's 2013 emissions rate of 927 lb/MWh; in addition, the proposed 

rate-based goals are based upon operations during a single, anomalous calendar year (2012), 

when South Point was operated at a significantly lower capacity factor than it has historically 

operated or is capable of due to unique operational and mechanical challenges. The commenters

said in 2012, South Point's steam turbine tripped offline unexpectedly when an alarm went off at 

a transformer; subsequent investigation revealed a breakdown of insulation inside the 

transformer, which required replacement and caused the plant to remain offline for an entire 

month. The commenters said altogether, the planned and unplanned outages for South Point in 
21

2012 amounted to more than six weeks when the entire plant was unavailable and additional time 

when either of the two combustion turbine generators was offline; as a consequence, 2012 is an 

unrepresentative year and should not provide the basis for EPA's proposed goals for Fort 

Mojave. 

Commenters stated EPA premises Fort Mojave's proposed rate-based goals on the absence of any 

opportunities for re-dispatch due to the fact that South Point is the only source located within 

Fort Mojave's jurisdiction; however, this fails to recognize the opportunities for South Point to 

serve load in other states, which may be expected to rely upon increased dispatch of a highly 

efficient NGCC plant like South Point to achieve reductions in emissions from their own affected 

EGUs (in particular, coal-fired facilities). The commenters said because the building block 

methodology is applied to Fort Mojave as though it were an island, the resulting rate-based goals 

also fail to reflect any increased dispatch of South Point attributable to increased cycling to 

support the integration of intermittent renewable generation sources (i.e., wind and solar) 

anticipated as part of states' compliance strategies. The commenters said as operations and 

cycling of South Point increase, so, too, does South Point's emissions rate; for these reasons, 

EPA's proposed emission performance goals are inappropriate and fail to reflect the role South 

Point is anticipated to play in achieving the Clean Power Plan's overall goals of increasing 

dispatch of lower-emitting fossil-fueled resources and supporting increased renewable 

generation. 

Commenters stated, in regards to the supplemental proposal, the Building Block methodology is 

ill-suited for Fort Mojave on a stand-alone basis. The commenters said when taken in isolation 

from the rest of the electricity grid, none of the Building Blocks can reasonably be expected to 

result in significant emission reductions for Fort Mojave. The commenters said Block 1 and 

Block 2 - heat rate improvements at steam affected EGUs and re-dispatch to NGCC affected 

EGUs, respectively - are assumed to result in no reductions because Fort Mojave's tribal lands 

contain no existing steam EGUs whose emissions can be reduced by making them more efficient 

or re-dispatching to the lowest emitting facilities.

Commenters stated Block 3 and Block 4 measures could hypothetically be implemented to some 

extent; but, to expect that these measures would achieve significant emission reductions would 

be unrealistic, and to impose such measures would be unfair. The commenters said while EPA 

then suggests potential alternate methodologies to apply Block 3 to tribes, the 

commenters agreed with EPA that it would be inappropriate to impose any RE goal on Fort 

Mojave pursuant to Building Block 3. 

Commenters stated the application of Block 3 to Fort Mojave would be unreasonable because 

Fort Mojave's electricity use is minuscule compared to the generation of South Point; it would be 

unreasonable to impose an emission reduction obligation on Fort Mojave that required it to 

develop utility-scale RE projects when it simply does not have the demand for electricity that 

would result in such RE being utilized by the tribe. The commenters said because any of the 

alternative methodologies for application of Building Block 3 would result in RE targets that 

dwarfed Fort Mojave's overall electricity demand, application of those methodologies to Fort 

Mojave and other areas of Indian country would clearly be arbitrary and wholly unrealistic. 
22

Commenters stated the Supplemental Proposed Rule would apply the same method and data 

sources in the Proposed Clean Power Plan to compute tribal goals for Block 4. The commenters

said given the marginal benefits that could be achieved vis-a-vis the emissions attributable to 

South Point, it makes little sense and would be a costly administrative exercise to require 

implementation of robust evaluation, measurement, verification and reporting methods for a 

jurisdiction as small as Fort Mojave. 

Commenters said the fact that the Building Block methodology results in no projected increase in 

South Point's dispatch relative to the 2012 baseline year and reduced dispatch relative to 2013 

levels illustrates why setting goals that effectively only apply to one affected source - on tribal 

lands where little electricity load is consumed - is per se unreasonable. The commenters said the 

fact that the proposed goals would essentially limit South Point to operations at only a fraction of 

what Building Block 2 assumes can be achieved on average for existing NGCC facilities should 

lead EPA to rethink its overall approach for establishing emission performance goals for areas of 

Indian country and for Fort Mojave in particular. 

Commenters stated because the Supplemental Proposed Rule's emission performance goals for 

Fort Mojave are inconsistent with the Clean Power Plan's broader emission reduction purpose, 

EPA should establish an alternative basis for such goals. The commenters proposed that the ratebased goals for Fort Mojave should be based on the highest emission rate observed in the 

previous five calendar years; this additional flexibility is warranted by the fact that Fort Mojave 

only contains one affected source - South Point. The commenters said unlike the emissions rates 

for states or other tribal areas, which contain multiple affected EGUs and, therefore, already 

reflect an average for any given calendar year (when one source's emissions may have been 

lower than historic levels, while another source's emissions were higher), it would be patently 

unfair to base the required emissions performance goal on emissions for one calendar year for a 

jurisdiction such as Fort Mojave, which has only one affected facility and therefore no 

opportunity for averaging among a broader fleet to achieve the goal. 

Commenters said EPA stated the following in the Proposed Rule for the States: "We view the 

proposed goals as providing rigor where required by the statute with respect to the amount of 

emission reductions, while providing states with flexibility where permitted by the statute, 

particularly with respect to the range of measures that a state could include in its plan. This 

approach recognizes that state plans for emission reductions can, and must, be consistent with a 

vibrant and growing economy..." The commenters said similar flexibility was not given to the 

Navajo Nation; a Navajo Nation plan adopted under the Proposed Supplemental Rule will not 

contribute to a "vibrant and growing economy."

Uintah-Ouray

Commenters stated EPA correctly noted that since the Uintah-Ouray reservation has no natural 

gas generation, building block two cannot be applied. The commenters said EPA also concluded 

that building block three should not apply to the Reservation, but asked for comment on whether 

it should be applied; it should not. The commenters said there is no record basis at all to assume 

that any renewable resources could be cost-effectively constructed on the reservation. The 

commenters said EPA correctly notes that the regional approach embodied in the main proposal 

and the Notice of Data Availability has no applicability to the reservation, because what some 
23

states have achieved or intend to achieve with renewable portfolio standards does not mean that 

the Uintah-Ouray Tribe could do the same. The commenters said EPA posits that it might 

fashion a renewable goal for the reservation based on technical potential, but there is a large 

difference between technical potential and actually developing renewable resources on the 

reservation; any assumption that renewable resources could be developed on the Reservation 

would need to be backed up by data showing who the developer might be, what the Tribe's role 

would be, and how needed tribal and other permits, financing, and transmission would be 

arranged. None of this information is in the record. 

Commenters were aware of extreme electric transmission constraints that exist for transmission 

of any significant generation located within the Reservation for use in major load centers or 

recognized market hubs. The commenters said Deseret Power Electric Cooperative was forced to 

default on construction indebtedness used to construct Bonanza and associated facilities; in very 

large part due to the lack of adequate transmission to transport and market output from the Unit 

to large load center outside the Uintah basin in which the plant itself is located; the existing 

Bonanza unit generates much more electricity than is needed or used within the Reservation or 

even the entire Uintah Basin area of relatively remote northeast Utah and western Colorado. 

Commenters stated the record lacks any information on how EPA would go about mandating or 

enforcing a renewable resource portfolio standard on the Reservation; EPA does not discuss any 

authority the Tribe might have to mandate renewable development, nor does EPA examine how 

EPA itself could possibly have authority under the Clean Air Act to order anyone to develop 

renewable resources on the Reservation. The commenters said the total size of electric load of all 

consumers located on lands owned by or held in trust for the Tribe is at most a few MegaWatts 

(peak demand); loads and activities of non-tribal concerns, operating on BLM or other non-tribal 

lands within the exterior boundaries of the historic Reservation fall outside the general civil or 

regulatory jurisdiction of the Tribe or of EPA. The commenters said EPA does not analyze nor 

discuss any authority under which these loads could be forced to utilize any given percentage of 

renewable resources. 

Comment 8: T&T Supplemental - BB1; HRI

Response 8: See section V.C. of the final rule preamble of the CPP for the EPA’s response to 

this comment and more information about Building Block 1 and the CO2 Emission Performance 

Rate and Goal Computation TSD for CPP Final Rule.

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

Commenters stated, in regards to the supplemental proposal, EPA stated that "[t]he methodology 

used to compute the proposed interim and final CO2 emission performance goals for U .S. 

territories and areas of Indian country with affected EGUs mirrors to the fullest extent possible 

the approach used to calculate goals for states discussed in section VII of the preamble to the 

[Proposed Rule for the States]." The commenters said the supporting information (spreadsheet 

and tables) for the calculation of the limit for the Navajo Nation includes a heat rate reduction of 
24

6% for the proposed goal that requires compliance by 2030 (4% for the alternative goal that 

requires compliance by 2025). 

Commenters strongly disagreed with EPA's assertion that NGS and FCPP can achieve 6% 

reduction in their heat rates. The commenters said the 6% heat rate improvement requirement 

was derived by EPA based on a national study. The commenters said it is inappropriate to apply 

the Building Block #1 requirement that was derived by EPA based on national data to the two 

power plants located on the Navajo Nation. The commenters said EPA should establish a lower 

heat rate improvement requirement that takes into account unit-specific considerations at NGS 

and FCPP, such as cost-effective energy efficiency improvement projects that are achievable at 

these plants, future emission control requirements (which will limit the availability of the plants 

to achieve heat rate improvements), and other regulatory constraints such as New Source Review 

requirements. 

Commenters stated both power plants have already invested significantly in emission controls 

because of other rules and, even with additional significant capital investments, would not be 

able to achieve a 6% heat rate improvement. The commenters said requiring a 6% heat rate 

improvement of these two power plants also ignores the fact that the Navajo Nation has also 

invested in the continued operation of the plants and has already suffered detrimental economic 

effects because of emissions reductions required under other rules. 

Comment 9: T&T Supplemental - BB2

Response 9: The EPA has established goals for areas of Indian Country with affected EGUs 

based on the application of the subcategory-specific emission performance rates to affected 

EGUs within those areas. See section VI of the final rule preamble for discussion of the 

subcategory-specific emission performance rates. See section V.D. of the final rule preamble of 

the CPP for the EPA’s response to this comment and more information about Building Block 2

and the CO2 Emission Performance Rate and Goal Computation TSD for CPP Final Rule 

supporting the final CPP.

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

Commenters stated, in response to the supplemental proposal, EPA was correct to state that 

applying Building Block #2 (Switching from coal-fired to natural gas combined cycle 

generation) to the Navajo Nation would not result in an adjustment to the goals of the Navajo 

Nation; there are no natural gas combined cycle ("NGCC") units for re-dispatch within the 

Navajo Nation.

Commenters opposed EPA's suggestion in the NODA regarding the adoption of the "minimum 

level of generation shift" on the Navajo Nation, which potentially would require existing coal

fired boilers to co-fire natural gas. The commenters said although the units at Four Corners 

Power Plant (FCPP) have the ability to combust a small quantity of natural gas for startup 

operations and early flame stabilization, the amount of heat input from natural gas combustion is 

limited to a small fraction of the total heat input to the units. The commenters said in order to cofire natural gas in these units, an enormous capital investment to modify the boilers and increase 
25

the natural gas supply infrastructure would be required. The commenters said the technical 

obstacles and costs associated with these modifications cannot be supported as cost-effective. 

The commenters said with respect to Navajo Generating Station (NGS), there are no nearby 

natural gas pipelines that could supply sufficient gas flow to the plant, and it would be 

unreasonably costly and difficult to site, permit, and construct a pipeline to the plant. Moreover, 

NGS was not designed to operate with natural gas even for purposes of startup. The commenters 

said co-firing would not be appropriate at either FCPP or NGS.

Comment 10: T&T Supplemental - RE Development – The EPA should clarify that states and 

tribes can take credit/or out-of-state emission reductions from RE projects without first entering 

into multi jurisdictional plans

Response 10: See section VIII 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, in regards to the supplemental proposal, developers must be allowed to 

freely negotiate the sale and delivery of electricity and RECs across jurisdictions (including state 

and tribal boundaries) through various contractual mechanisms, such as power purchase 

agreements, without fear that the value of those projects will be severely limited by an inability 

to transfer the RECs for use to address CO2 emission reductions under any state plan. 

Commenters stated on a related note, EPA seeks comment in its NODA on whether each state's 

(and tribe's) RE target should be based on the RE potential available across a multi-state region 

in which the state or tribe is located. The commenters opposed this approach, in particular for 

tribes. The commenters said currently, there are no RE generating resources located on the 

Navajo Nation, and development of such resources has proven challenging, despite the 

abundance of natural resources well suited for renewable energy projects. The commenters

added the Navajo Nation faces a very different situation from its neighboring states, thus, it 

would be improper and unfair to assume growth of such resources on the Navajo Nation based 

on growth rates of nearby states.

Commenters stated the Proposed Rule states that EPA "views the existing RPS requirements as a 

reasonable foundation" to quantify the CO2 emission reductions achievable based on increases in 

renewable generation; however, state RPS requirements do not specify that the energy from RE 

projects must come from in-state facilities. The commenters said for example, in California, 

much of the renewable generation that counts toward the RPS comes from outside of the state; 

there is absolutely no reason why EPA should impose a more rigorous requirement than the 

states themselves impose. The commenters added the Proposed Rule recognizes that different 

parts of the country have different amounts of RE resources; with respect to Building Block 3, 

the Proposed Rule identified six different regions and developed annual RE growth factors and 

maximum RE generation targets separately for each region; accordingly, some geographic 

regions are capable of developing more RE than needed to meet their own 111(d) plans. The 

commenters said in these situations, incentives should exist for the development of additional RE 
26

generating resources through the sale or export of CO2 emissions to other states. The 

commenters said EPA has stated it intends to provide such flexibility to states, including 

allowing states to enter into cap-and-trade programs; generation on tribal lands should be treated 

similarly.

Comment 11: T&T Supplemental - BB3; RE

Response 11: See section V.E. of the final rule preamble of the CPP for the EPA’s response to 

this comment and more information about Building Block 3 and the CO2 Emission Performance 

Rate and Goal Computation TSD for CPP Final Rule supporting the final CPP.

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.

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

Commenters stated technical potential is based on including in a state's territory both tribal and 

federal lands, each of which adds constraints and additional technical challenges. The 

commenters said in fact, tribal lands should not be included in assessing a state's RE potential at 

all, considering that tribes are not subject to the Proposed Rule. The commenters said these 

drawbacks must be addressed before considering any option related to technical potential.

Commenters commended EPA for proposing a plan to address emissions and pollution from 

fossil-fueled power plants and for invoking a transition from coal-fired power plants to cleaner 

sources of energy. While the commenters are supportive of EPA's proposed Clean Power Plan, 

the commenters asked that EPA consider the following: 

1. A stronger role for renewable energy and more stringent state renewable energy targets; 

2. Full consideration of all impacts of biomass energy and its 'carbon neutrality' prior to 

allowing it as a strategy for states to meet their emission reduction goals; and 

3. Allow tribal consultation and input as states begin developing clean power plans for 

EGUs located in Ceded Territory.

Commenters stated EPA should clarify in the final rule that renewable resources built on Indian 

Lands are eligible for demonstrating compliance within a state or regional implementation plan. 

The commenters said EPA has stated during stakeholder discussions that new renewable projects 

built on Indian Lands do qualify as eligible resources under the 111(d) proposal. The 

commenters requested that upon issuance of the final rule, EPA clarify in writing that as long as 

a renewable generating resource built on Indian Lands is quantifiable and not double counted, 

then that resource is eligible for inclusion in a state's compliance plan.

Commenters stated, in regards to the supplemental proposal, Building Block #3 is that it is not 

appropriate for the Navajo Nation. The commenters said that Building Block #3 is not practically 

applicable to the Navajo Nation; not only is the Navajo Nation's electricity use within the bounds 
27

of the reservation small compared to the electricity generated by NGS and FCPP, the majority of 

which leaves the reservation, the Navajo people already obtain the majority of their electricity 

from low carbon resources, including zero carbon hydro-electric sources.

Commenters stated that they strongly urge EPA to strengthen the rule, primarily by accounting 

for achievable reductions through renewable energy and energy efficiency. Commenters said this 

should apply to territories and tribes as well. Commenters said as with states, EPA should sets 

strong standards for tribes and territories based on what can be achieved in reductions for 

renewable energy based on technological and market factors.

Comment 12: T&T Supplemental - BB4; EE

Response 12: The EPA is not including building block four (demand-side energy efficiency) in 

the final BSER determination. See section V.A. of the final rule preamble of the CPP for the 

EPA’s response to this comment and more information about Building Block 4 and the CO2

Emission Performance Rate and Goal Computation TSD for CPP Final Rule supporting the final 

CPP.

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

Commenters stated, in regards to the supplemental proposal, demand-side reductions can be a 

beneficial tool. The commenters said while the Navajo Nation offers energy efficiency programs, 

a significant portion of the Navajo people have very poor access to electricity; as a result, the 

9.15% demand reduction goal is very challenging and not especially beneficial. The commenters 

said EPA's demand-side goals were developed based upon an analysis of state data, where 

electricity use and incomes are far greater and the opportunities for demand-side reductions also 

much greater. The commenters said the use of state information to develop goals for the Navajo 

Nation results in a goal that does not make any sense for the Navajo Nation; for example, the 

state of Wyoming, with a per capita electricity demand that is 778% that of the Navajo Nation, 

and per capita income that is 476% that of the Navajo Nation, has an energy efficiency goal that 

is only 106% of that of the Navajo Nation.

Commenters stated electricity consumption on the Navajo Nation is very different than in the 

states; at least 32% of the Navajo Nation population does not even have electricity. The 

commenters said per capita electricity consumption on the Navajo Nation is already roughly one 

third that of its neighbors and about half that of the most efficient state. The commenters said 

moreover, the majority of electricity used on the Navajo Nation is from hydroelectric sources. 

The commenters said further demand-side reduction measures therefore will not result in any 

significant CO2 emission reductions. The commenters said unlike the states - per capita energy 

consumption on the Navajo Nation actually needs to increase in the future to promote economic 

development; widespread poverty on the Navajo Nation makes it difficult to increase access to 

affordable electricity while also paying for the demand-side efficiency incentive programs that 

form the basis of EPA's Building Block #4 program for the states. The commenters believed that 

EPA should reconsider how Building Block #4 is applied to the Navajo Nation. 
28

Commenters recommended that the EPA remain attentive to the existing challenges of energy 

access in areas where electrification rates are low, and incorporate these concerns into goal 

calculations such that the Clean Power Plan simultaneously supports the expansion of energy 

access while advancing the development of clean energy resources. The commenters stated that 

EPA should encourage the adoption of renewable energy and efficiency technologies for 

electrification of low-served areas; as these areas gain increased access to electricity, they have 

the potential to leapfrog old, energy-intensive technologies in favor of new, highly efficient 

resources that have the potential to provide long-term dividends to such regions. The 

commenters noted that an estimated one-third of the Navajo do not have access to electricity and 

in light of high "last-mile" costs associated with the electrification of dispersed populations 

within parts of Indian country, distributed renewable energy generation provides a potentially 

valuable solution.

Comment 13: Tribal set-aside should be established as part of an interstate emissions credit 

trading program

Response 13: See section VIII 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 as part of an annex to the Regional Haze Rule (Annex) that was adopted in 

the late 1990s, an annual SO2 tribal set-aside of 20,000 tons was made available to Indian Tribes 

within a nine-state region regardless if such Tribes had major industrial sources emitting SO2. 

The commenters said this set-aside grew out of multiple discussions among the Western 

Regional Air Partnership's (WRAP) partners and participants where issues of equity and 

economic development kept coming up during conversations with respect to Tribes that had 

hardly contributed to visibility impairment in the West but whose environment and health had 

been adversely affected by neighboring jurisdictions with sources emitting significant SO2 

amounts. The commenters said the Annex provided that the Tribal set-aside was "intended to 

help ensure equitable treatment for tribal economies and prevent barriers to economic 

development." The commenters said the same rationale for a Tribal set-aside exists today and 

should be incorporated into any national trading program that grows out of the Proposed Rule. 

Comment 14: State implementation plan development should include Tribes

Response 14: See section VIII 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:
29

Commenters stated the State Implementation Planning process must include tribal leaders at the 

table. The commenters said tribes can be treated as states under Section 301(d) of the Clean Air 

Act; as such, there is no reason why EPA should not have involved them in meetings with states 

concerning multistate planning efforts. The commenters suggested that this outreach be a 

significant part of the SIP process. 

Commenters stated EPA did not consult with the Crow Nation, did not consider the economic 

impacts on the Crow Nation, and did not provide a less intrusive alternative to the severe effect 

on the Crow Nation of this Proposed Rule. The commenters said in combination, EPA violated 

its trust responsibility to the Crow Nation and must provide a substantive alternative and/or 

mitigation of the Proposed Rule.

Comment 15: T&T Supplemental - 2012 Baseline; coal retirements

Response 15: See section VI.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:

Commenters stated, the supplemental proposal does not factor out recent and near-term coal 

plant retirements from its goal-setting formula. The commenters said because the supplemental 

proposal uses 2012 as its baseline year for setting emission targets, it includes data from units 

that were operational in 2012 but that have since retired, as well as from plants that are now 

operational but will retire between now and the beginning of the compliance period. The 

commenters said in the CPP context, this oversight distorts the actual generation pool in affected 

jurisdictions and will, in most cases, give "free" emission reduction credits rather than driving 

additive emission reductions. 

Commenters said recent and near-term retirements are relevant for the supplemental proposal 

because three of the five Four Corners units have already retired but are included in the 

emissions target for the Navajo Nation. The commenters said EPA must recalibrate the targets 

for the Navajo Nation to reflect this fact. The commenters urged EPA to use as its baseline the 

most recent full year's data at the time a state submits its implementation plan for the agency's 

approval (i.e., if the state submits its plan in 2016, 2015 data would be used for the baseline). 

The commenters said if the Navajo Nation seeks and receives authority from EPA to develop and 

administer an implementation plan, it should use data from the most recent full year available at 

the time it submits the plan for EPA's approval; if the Nation declines to develop a plan, EPA 

must use also use the most recent full year's data for the baseline in a federally-administered 

plan. 

Commenters added that EPA should also omit from the goal-setting exercise plants that are 

operating at the time states submit their implementation plans but which have announced and 

enforceable retirement obligations before the compliance period begins in 2020. The commenters

said EPA comments in the preamble to the supplemental proposal that one of the units at the 

Navajo Generating Station may retire or curtail dispatch by 2019 to comply with Best Available 

Retrofit Technology requirements. The commenters said if this unit is officially announced for 
30

retirement by the time the Navajo Nation's implementation plan is submitted to EPA (or 

developed by the agency) and subject to an enforceable requirement that it retire before 2020, it 

should also be omitted from the goal-setting exercise under the supplemental proposal. 

Commenters stated that the proposed best system of emissions reduction, or BSER, is not 

flexible enough. And when you combine it with a reexamination of the building block analysis, 

commenters stated they hope is that EPA would be open to considering the use of other baseline 

years, other than 2012 in its analysis and eventual revising of the BSER for the Navajo Nation. 

Commenters stated that Arizona Public Service Company, APS, operates a generation fleet 

consisting of coal fired, gas fired, and nuclear units to serve the needs of over 1 million APS 

customers, also has an increasing portfolio of renewable energy and manages a robust behind the 

meter energy efficiency program, and owns and operates the Four Corners Power Plant and owns 

a portion of the Navajo Generating Station, both of which are located on the Navajo Nation and 

subject to the proposed supplemental rule.

Commenters stated that based on meeting with EPA representatives from Navajo Nation and the 

Salt River Project, operator of the Navajo Generating Station, the only other power plant located 

on the Navajo Nation, and based on all these discussions and analysis, commenters supported

EPA's recognition that closure of three units at the Four Corners Power Plant and SRP's expected 

shutdown and curtailment of generation at the Navajo Generating Station by 2019 represent 

approximately a 30 percent reduction of total 2012 carbon emissions on the Navajo Nation. 

Commenters stated that in setting the carbon emission rate goals for the Navajo Nation EPA used 

the same four building block methodology it used to set the state-specific goals. Commenters

stated that this methodology used 2012 as the emissions baseline year and in which to apply 

specific criteria. Commenters, however did not support using 2012 as the baseline year for 

studying the future emission rate goals for the Navajo Nation because 2012 was not 

representative of future unit operations at the Four Corners facility. Commenters stated that in 

general, 2012 is a poor choice to use as a baseline year for coal fired power plants, including 

Four Corners because the depressed price of natural gas during 2012 caused lower than normal 

dispatch of many coal fired units. 

Commenters stated that conversely, as natural gas prices have subsequently risen utilities have 

increased the dispatch of coal-fired units and additionally, forced outages, which were 30 percent 

higher at Four Corners in 2012 than the average value at Four Corners since 2005, are out of 

control of unit operators and should be considered when establishing a representative baseline 

year.

Commenters recommended that EPA not use 2012 as the baseline year and allow a much longer 

look back period to at least 2005 in order to establish a more representative baseline year. 

Commenters stated that Bonanza unit is a single-unit resource and the year 2012, on which the 

standard is based and was developed, in that year Bonanza experienced prolonged and unusual 

outages due to plant maintenance outages that are usually only scheduled once every few years -

therefore 2012 is not a representative year on which to base Bonanza's carbon standard.
31

Commenters encouraged EPA to consider a baseline year other than 2012 since 2012 was not a 

representative year for the operation of NGS or Four Corners and the operators are currently 

reviewing plant emissions data and will provide recommendations to EPA in written comments.

Comment 16: T&T Supplemental - Should be given flexibility to join larger regional solutions

Response 16: For the EPA’s response to this comment, see section VIII of the final rule 

preamble of the CPP and the CO2 Emission Performance Rate and Goal Computation TSD for 

CPP Final Rule supporting the final CPP.

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

Commenters stated, in regards to the supplemental proposal, more reductions can also be gained 

through energy efficiency for states, territories and tribes, as is already being shown in several 

states, and these gains should be reflected in EPA's standards. The commenters said tribes and 

territories should also be given flexibility to join larger regional solutions, especially given that 

many tribes are small and would benefit from being part of larger, regional compliance solutions. 

The commenters said tribes in particular have a keen stake in a strong rule. The commenters said 

tribes have long continual experience with climate, wildlife, land and natural resources in North 

America and know intimately how climate change is already impacting our shared landscape. 

The commenters have teamed up with tribes to advance policies that seek to solve climate 

change. 

Comment 17: T&T Supplemental - Mass based goals

Response 17: For the EPA’s response to this comment, see section VII of the final rule preamble 

of the CPP the CO2 Emission Performance Rate and Goal Computation TSD for CPP Final Rule 

supporting the final CPP.

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

Commenters stated, in regards to the supplemental proposal, the flaws associated with EPA's 

proposed rate-based goals intensify with respect to EPA's proposed illustrative mass-based 

equivalent values for Fort Mojave. The commenters said the Mass Conversion TSD proposes 

two methodologies for illustrating potential ways to convert from a rate-based goal to a massbased goal. The commenters said while EPA clarified upon publication of the Mass Conversion 

TSD that the mass-based equivalents are merely illustrative, the commenters nevertheless took

issue with the extreme stringency of the model interim and final mass-based equivalent values 

for Fort Mojave, which are both set at 528,000 MTCO2 (or 532,000 MTCO2 if emissions from 

both South Point and assumed incremental new generation capacity are covered by the goal). 

The commenters said these mass-based equivalent values are significantly lower than South 

Point's 2013 mass emissions of 813,618 MTCO2, which emissions themselves only reflect South 

Point operating at approximately a 42% capacity factor; thus, not only would EPA's proposed 

mass-based equivalents limit South Point to only a fraction of its capacity - less than 27.5%; they 
32

would also contradict the assumed operational role that South Point will play in achieving the 

reductions available through Building Block 2. 

Commenters said while it is true that there are no opportunities for re-dispatch of NGCC 

facilities under Block 2 within Fort Mojave's tribal lands, South Point is connected to the 

Western Electricity Coordinating Council ("WECC")-wide grid, which covers all or part of 13 

U.S. states. The commenters said it can reasonably be assumed that South Point may be expected 

to operate at a higher capacity factor in the future in order to help satisfy the emission 

performance goals of neighboring jurisdictions; therefore, EPA's proposed illustrative massbased equivalents would not only proscribe South Point from operating as it most recently has, 

but would unduly limit it from being dispatched at higher rates. The commenters said this would, 

in turn, be contrary to the overall goal of the Clean Power Plan of limiting power sector GHG 

emissions through dispatch of the lowest-emitting fossil fuel-fired generating sources. 

Commenters said by calculating the Supplemental Proposed Rule's proposed rate-based goals 

and the Mass Conversion TSD's illustrative mass-based equivalents as though South Point were 

operated in isolation from the rest of the electricity grid, EPA has proposed goals that are 

inappropriate for Fort Mojave and South Point and contravene both the basis and purpose of the 

Clean Power Plan, which is premised upon the uniquely interconnected nature of the electricity 

grid and redispatch to the most efficient generating sources. The commenters said although 

EPA's proposed goals are supposed to reflect Fort Mojave's "unique conditions", they do not. 

Instead, they would arbitrarily constrain South Point to only a fraction of its historic capacity and 

prevent it from playing the role it is likely to play in other states' achievement of their respective 

goals. 

Commenters stated, in regards to the supplemental proposal, to propose both an interim and final 

rate-based goal for Fort Mojave equivalent to South Point's 2013 emissions rate of 927 lb/MWh. 

The commenters asserted EPA should take an expansive approach to allowing jurisdictions to 

translate their rate-based goals on a mass basis, as EPA has indicated it will do. The commenters 

asserted that a reasonable translation of EPA's rate-based goals for Fort Mojave would assume an 

80% capacity factor for South Point. The commenters said while Block 2 assumes re-dispatch to 

NGCC facilities at a 70% capacity factor on average, EPA recognizes that the 70% figure 

represents an average and at least some NGCC facilities dispatch at an 80% or higher rate. The 

commenters said given that South Point may need to be operated at a higher than 70% capacity 

factor due to WECC-wide demand for efficient generation to replace higher emitting coal-fired 

sources, assuming an 80% capacity factor in translating to mass-based goals would provide an 

adequate buffer for South Point, and is wholly reasonable. The commenters said based on the 

proposed rate-based goals, this capacity factor would result in interim and final mass-based 

equivalent values of approximately 1,561,000 MTCO2.

Commenters further supported the ability to convert the Navajo Nation rate based goal to a mass 

based goal in the ability of the Navajo Nation to establish a multi-jurisdictional agreement with 

states to allow trading of emission credits.
33

Commenters asserted that these elements are vital to successful compliance with the final rule, 

and will allow Navajo Nation the flexibility it is seeking.

Comment 18: T&T Supplemental - Commenters agreed with EPA determination that 

compliance with NGS BART provisions and Regional Haze Rule will result in compliance with 

CPP

Response 18: See section X.C. 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 concurred with the Environmental Protection Agency's (EPA) determination that 

Indian Country, specifically Navajo Generating Station (NGS), will meet the proposed carbon 

standards of the Clean Power Plan through compliance with the NGS Best Available Retrofit 

Technology (BART) provisions of the Clean Air Act and the Regional Haze Rule. 

Commenters stated Section V of the Supplemental Proposal to the Clean Power Plan addresses 

the impacts of the EPA's Proposed Action, specifically the proposed rule's air impacts. The EPA 

states in its proposal that it does not expect any additional emission reductions from areas of 

Indian Country with affected Electrical Generating Units (EGU) due to the area's expected 

compliance with BART requirements. The commenters said pursuant to the NGS BART rule, 

one EGU will shut down or equivalent generation will be curtailed to comply with requirements 

for BART at NGS by 2019; this shutdown or equivalent curtailment will result in substantial 

CO2 reductions and the Navajo Nation meeting the proposed goal without additional actions. 

Commenters stated the EPA's Supplemental Proposal for carbon emissions recognizes the 

balance struck between NGS constituents and the EPA to develop mutually acceptable solutions 

for the operation of NGS. The commenters said the EPA's conclusion that the shutting down of 

one EGU consistent with BART requirements is sufficient to meet the carbon emissions 

reduction proposal, is further evidence of the agency's commitment to achieve quality air 

standards and ensure the continued vitality of NGS and the CAP, both of which are critical to 

Arizona's economy and its people. 

Comment 19: T&T Supplemental - EPA Correctly Recognized the Emission Reductions that 

Have Taken Place at NGS and FCPP Because of Other Rules

Response 19: See section X.C. 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 EPA correctly recognized in the supplemental proposal that the participants 

in NGS and FCPP have made significant investments to achieve emission reductions under other 
34

EPA rules. The commenters said the Navajo Nation has also made investments to assure future 

operation of the plants, including by purchasing the Navajo Mine to ensure a continued supply of 

coal to FCPP. The commenters said additionally, these other EPA rules have negatively affected 

the Navajo Nation in terms of job losses and decreased revenue to the Navajo Nation 

government. The commenters said annual losses to the Navajo Nation due to the three-unit 

shutdown at FCPP will be $86 million; NGS and its associated mine (Kayenta Mine) were 

estimated to contribute $13 billion to the Navajo Nation economy between 2020 and 2044; 

however, that contribution will be significantly diminished as a result of EPA's Regional Haze 

Rule for NGS. 

4.11 STATE-SPECIFIC GOAL COMPUTATION COMMENTS

Section 4.11 covers public comments related to the state-specific computation procedure of the 

final and interim goals. 

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: AL - Plants due to retire

Response 1: As explained in section VI of the final rule preamble of the CPP, the EPA relies on 

a historical 2012 data to inform the representative baseline year. It does not project a future 

baseline of units based on expected retirements. For the EPA’s response to this comment, see 

the CO2 Emission Performance Rate and Goal Computation TSD for CPP Final Rule supporting 

the final CPP.

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

Commenters stated that the EPA's target-setting for Alabama does not account for the following 

planned coal unit retirements:

Colbert Fossil Plant. The Tennessee Valley Authority has announced plans to retire all five of its 

coal-burning units, totaling 1,350 MW, at this facility in northwest Alabama. Although no 

specific retirement date has yet been set, under the terms of a Federal Consent Decree, it cannot 

occur later than 2019. TVA has already idled Unit 5, and this unit produced no generation in 

either 2013 or (so far) in 2014. In 2012, the Colbert units accounted for 3,364,920 MWh of 

generation that produced 3,718,102 tons of CO2 emissions.

Widows Creek Unit 8. TVA has announced that it will retire Unit 8 (550 MW) by November 

2014. In 2012, Unit 8 accounted for 1,949,090 MWh of generation that produced 2,148,198 tons 

of CO2.
35

Gorgas Units 6 and 7. Alabama Power Company recently announced that it would retire these 

two units, totaling 250 MW, by 2016. In 2012, these units accounted for 147,124 MWh of 

generation that produced 195,390 tons of CO2.

Commenters said the electric generation and carbon emission levels from these units were 

included in Alabama's baseline emissions rate, but the EPA did not include the planned 

retirements of these units when calculating Alabama's emission rate target. Commenters said 

collectively, these units accounted for more than 5.4 million MWh of coal generation in 2012. 

Commenters indicated applying these retirements to EPA's emissions rate calculation lowers 

Alabama's emission rate by 43 lbs/MWh or 9.3 percent of the 2030 target reduction.

Comment 2: AL - Planned coal to natural gas conversions

Response 2: The EPA relies on a historical data set rather than a projected data set for its 

baseline. See more discussion on this issue in section VI of the final rule preamble of the 

CPPand the CO2 Emission Performance Rate and Goal Computation TSD for CPP Final Rule 

supporting the final CPP. While these planned conversions are not part of the baseline and 

BSER quantification, states/sources could potentially recognize the corresponding reductions in 

their compliance plans as discussed in section VIII of the final rule preamble of the CPP.

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

Commenters said that several coal-burning generating facilities in Alabama are going to be 

converted to run natural gas and the conversions will reduce CO2 emissions achieving 14% of 

the target reduction.

Commenters indicated Alabama Power has decided to convert coal-burning units at its Gaston, 

Barry, Gadsden, and Greene County facilities to run on natural gas. Commenters said the 

efficiency of such units typically is lower than that of to new or existing NGCC units, and said 

that gas conversion is not particularly cost-effective. Commenters said nevertheless, Alabama is 

free to rely upon gas conversions for compliance purposes, and compared to the coal generation 

they replace, they will result in lower carbon emissions.

Gaston Units 1-4. Commenters said for example, at Plant Gaston, to comply with the EPA's 

Mercury and Air Toxics (MATS) Rule, Alabama Power is converting all four of its coal-fired 

units to run on natural gas. Commenters said the conversion will be in effect by April 2016, and 

indicated the converted units will not be as efficient as NGCC units. Commenters said that 

Alabama Power's permit application for the conversion project reveals that the converted units 

have the potential to emit more than 1.2 million pounds of greenhouse gases per hour at full load.

Commenters added that this translates to approximately 1,196 lbs/MWh, which is above the 

average emission rate for Alabama's NGCC units (877 lbs/MWh), but added that the converted 

units will be substantially more efficient than Alabama's coal units, whose average emission rate 

is 2,264 lbs/MWh.

Commenters stated that the converted units will be run infrequently, in a peaking capacity. 

Commenters said that although precise figures are not publicly available, it is reasonable to 
36

assume that as peaking units, the converted units' capacity factors will rarely, if ever, exceed 15 

percent. Commenters said this would mean 1,423,008 MWh of new gas generation with an 

emissions rate of 1196 lbs/MWh instead of the figures assumed in EPA's 2012 emission rate 

calculation: i.e. 3,190,258 MWh of coal generation at an emission rate of 2,264 lbs/MWh.

Barry Units 1-3. Commenters said similarly, at its Plant Barry, near Mobile, Alabama Power 

plans by 2016 to cease burning coal at three units totaling 578 MW. Commenters said that Units 

1 and 2 already have gas capability; such capability will be added to Unit 3. Commenters said in 

2012, these three units had an average capacity factor of 15 percent, and said it is reasonable to 

assume a similar capacity factor going forward, as Alabama Power has stated that two of the 

units will be used only on a limited basis.

Commenters said that in 2012, Barry Units 1-3 accounted for 772,069 MWh of generation. 

Commenters said assuming similar levels of generation in the future, and emission rates similar 

to the converted Gaston units (i.e. 1,196 lbs/MWh), the Barry units will produce 412,285 fewer 

tons of CO2 emissions than in 2012.

Greene County Units 1 and 2. Commenters said that Alabama Power will convert these two 

units, totaling 568 MW, to run on natural gas by April 2016. Commenters said it is unclear 

whether the converted units will be used solely in a peaking capacity or run more frequently. 

Commenters said that in 2012, the units were responsible for 2,015,762 MWh of generation, 

which equates to a capacity factor of 41 percent. Commenters said assuming similar levels of 

generation in the future, and emission rates similar to the converted Gaston units (i.e. 1,196 

lbs/MWh), the converted units will produce 1,205,425 fewer tons of CO2 emissions than in 

2012.

Gadsden Units 1 and 2. Commenters said these Alabama Power units, totaling 138 MW, are 

already equipped to run on natural gas. Commenters indicated that Alabama Power has stated 

they will burn natural gas almost exclusively going forward. Commenters said that in 2012, these 

units produced 222,100 MWh of generation that EPA's analysis counts as coal generation,

which equates to a capacity factor of 18 percent. Commenters said assuming similar levels of 

generation in the future, and emission rates similar to the converted Gaston units (i.e. 1,196 

lbs/MWh), the Gadsden units will produce 118,601 fewer tons of CO2 emissions than in 2012.

Commenters said in summary, the gas conversions at Gaston, Barry, Greene County, and 

Gadsden will collectively result in the removal of over 6 million MWh of coal generation and its 

substitution with lower generation levels (approximately 4.4 million MWh) of lower-emitting 

natural gas. Commenters said they conservatively estimate that the conversions will reduce 

Alabama's 2012 emission rate by another 66 lbs/MWh or 14 percent of the target reduction.

Comment 3: AL - Recent and planned RE projects

Response 3: See section V.A of the final rule preamble for a discussion of building block three 

quantification in the final CPP.

The following are summaries of the specific public comments under this comment:
37

Commenters provided information on recent and planned renewable energy projects. 

Commenters said that Alabama Power has entered two agreements to import a total of 404 MW 

of cost-effective wind generation, along with associated renewable energy credits (RECs), from 

Oklahoma and Kansas. Commenters said the utility received approval for the first project, known 

as Chisholm View, in September 2011. Commenters said that under the terms of the agreement, 

Alabama Power receives 202 MW of generation from a wind farm in north-central Oklahoma, as 

well as the associated RECs, over a twenty-year term. Commenters said the project came online 

in December 2012.

Commenters said Alabama Power received approval for the second project, known as Buffalo 

Dunes, from the PSC in September 2012. Commenters said the project is functionally similar to 

Chisholm View: Alabama Power will receive 202 MW of generation from a wind farm in 

southwestern Kansas, as well as the associated RECs, over a twenty-year term. Commenters said 

the project came online in December 2013.

Commenters said that although the precise capacity factors associated with these projects are not 

publicly available, reasonable approximations can be inferred from the utility's statements. 

Commenters said that Alabama Power has stated that the projects amount to 3 percent of the 

electricity consumed by its customers, and that in 2012, Alabama Power had retail sales totaling 

53,946,766 MWh. Commenters said three percent of that figure is 1,618,403 MWh, and dividing 

that figure by 8,784 hours and by 404 MW produces a capacity factor of 45.6 percent.

Commenters said that similarly, Alabama Power has stated that the two projects are sufficient to 

power the equivalent of 115,000 homes. The average Alabama home consumes 14,241 kWh per 

year. The amount of electricity consumed by 115,000 such homes equates to 1,637,715 MWh. 

Commenters said dividing that figure by 8,874 hours and by 404 MW yields a capacity factor of 

46.1 percent.

Commenters said assuming a 46 percent capacity factor, these deals will result in 1,632,419 

MWh of carbon-free generation that goes into the denominator of EPA's emission rate equation. 

Commenters said this in turn lowers Alabama's 2012 emission rate by 22 lbs/MWh or more than 

4 percent of the target reduction.

Commenters said another recently announced renewable project is the planned Redstone Arsenal 

solar array. Commenters indicated that Redstone Arsenal is a U.S. Army post and garrison 

located near Huntsville, Alabama within TVA territory, and said it will soon be home to the 

largest solar power array in Alabama. Commenters said that as part of its goal to have 25 percent 

of its energy produced from renewable sources by 2025, the Army has solicited proposals for an 

array that will provide up to 18,000 MWh of solar-generated electricity for the arsenal. 

Commenters said the project is estimated to be 10 to 14 megawatts in size, with as many as 

50,000 solar panels. Commenters said the Army has cited the energy security benefit the array 

will provide and noted that sharp declines in the installed price of solar power have made the 

project financially attractive.

Comment 4: AL - Summary of planned carbon-reducing measures
38

Response 4: See section VIII of the final rule preamble of the CPP for a discussion state plans 

components.

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

Commenters summarized the carbon-reducing measures planned for Alabama. 

Commenters said that in total, accounting for the retirements, conversions, and renewable energy 

procurements, all of which will occur even in the absence of the proposal, Alabama will lower its 

carbon intensity by 132 lbs/MWh, equating to 30 percent of Alabama's target reduction. 

Commenters said that in addition, the EPA includes in the target-setting - and Alabama may 

credit toward compliance - the state's existing renewables (2,776,554 MWh), existing energy 

efficiency (56,045 MWh) and existing "at-risk" nuclear (2,329,528 MWh). Commenters

indicated that with these credits, Alabama is almost 45 percent of the way toward its target more 

or less as a matter of business as usual. 

Comment 5: AL - Summary of Alabama's Emission rate target

Response 5: For the EPA’s response to this comment, see the CO2 Emission Performance Rate 

and Goal Computation TSD for CPP Final Rule supporting the final CPP.

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

Commenters summarized the EPA-calculated emission rate target for Alabama, and stated 

that Alabama is making good progress and the goal is achievable and should be at least as 

stringent as the proposed target.

Commenters said that the EPA has proposed a carbon emission rate target for Alabama of 1,059 

pounds per megawatt-hour (lbs/MWh) to be achieved by 2030, and an interim average target of 

1,147 lbs/MWh between 2020 and 2029. Commenters said that Alabama's proposed target 

represents a 27 percent emission rate reduction from an initial 2012 emission rate of 1,518 

lbs/MWh.Commenters expressed support of the EPA's finalization of a 2030 target for Alabama 

that is at least as stringent as the proposed target.

Commenters said that Alabama's target is both modest and achievable. Commenters said that the 

EPA's building blocks determine the target for Alabama, there is nothing requiring Alabama to 

follow the same path for compliance. Commenters said that as the EPA emphasizes in the 

proposal, states may elect to pursue some building blocks more extensively and others less 

extensively than assumed by the EPA, and may even choose other measures, so long as they 

meet the overall target reduction. Commenters said that states retain the flexibility to determine 

the compliance path that makes the most sense under their unique facts and circumstances.

Commenters said that the EPA's target-setting does not take into account carbon-reducing 

measures that Alabama had begun approving and putting into place prior to the proposal. 

Commenters said when those measures - which include decisions to retire or convert aging coal 

units and to begin investing in clean energy resources - are taken into account, we can see that 
39

Alabama is already almost halfway toward its target. Commenters said Alabama can get the rest 

of the way there through a combination of modest natural gas re-dispatch and stepped up 

investments in renewable generation and energy efficiency.

Commenters summarized the emissions reductions associated with the EPA's analysis as follows:

Building Block 1: Lowers Alabama's 2012 emission rate by 63 lb/MWh or 14% of the target 

reduction

Building Block 2: Lowers Alabama's 2012 emission rate by 126 lb/MWh or 27% of the target 

reduction 

Building Block 3a (nuclear): Lowers Alabama's 2012 emission rate by 30 lb/MWh or 7% of the 

target reduction

Building Block 3b (renewables): Lowers Alabama's 2012 emission rate by 160 MWh or 35% of 

target reduction. (Note: under the EPA's assumptions, Alabama does not reach the regional 10% 

target before 2030)

Building Block 4: Lowers Alabama's 2012 emission rate by 80 lb/MWh or 17% of the target 

reduction.

Comment 6: AK - The EPA lacks authority under the CAA to issue these regulations

Response 6: The EPA is not including emission performance goals for Alaska in this final rule. 

See section VII.F of the preamble for discussion of this issue.

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

Commenters argued that EPA lacks authority under the Clean Air Act to issue these regulations. 

The commenters also argued that EPA has not presented facts or reasoning to support the 

application of the rule in Alaska.

Commenters stated the Proposed Rule exceeds EPA's authority under the Clean Air Act (CAA). 

Commenters stated first, application of section 111 (d) is limited to source categories that are not 

already regulated under section 112; EPA has already elected to regulate coal-fired power plants 

under section 112. Commenters stated second, regulations governing emissions from new 

sources under section 111 (b) are a necessary predicate for any section 111(d) regulation of 

existing sources; here, EPA has only issued proposed section 111(b) regulations. Commenters

stated third, the Proposed Rule impermissibly expands EPA's authority beyond air pollution 

control into the management of state energy generation and usage. Commenters stated fourth, the 

Proposed Rule mandates firm, numerical emission targets rather than the guidelines and 

procedures contemplated by section 111(d). Commenters stated this Proposed Rule would 

effectively negate state authority to evaluate EPA's guidelines in the context of costs, technical 

and physical feasibility, energy needs, other environmental impacts, and the "remaining useful 

life of the existing source." Commenters stated fifth, the BSER measures proposed by EPA 
40

improperly include measures beyond the physical or legal control of the regulated sources. 

Commenters stated standards of performance established under section 111 (d) must be 

achievable through source-level, inside-the-fence line measures. Commenters stated sixth, the 

Proposed Rule conflicts with the balance of federal and state authority with respect to energy 

policy established in the Federal Power Act.

Commenters added most frustrating for AK, EPA simply has not presented facts or reasoning to 

support the application of this rule in Alaska. Commenters stated EPA's foundational 

assumptions regarding the generation and transmission of electricity, particularly the premise of 

a robust interconnected grid, have little relevance to Alaska. Commenters added the technical 

analyses - including the crucial Integrated Planning Model (IPM) and Regulatory Impact 

Analysis (RIA) - fail to evaluate the application of this rule in our state. Commenters concluded 

EPA has no basis to conclude that the costs of implementing the proposed BSER measures in 

Alaska would be reasonable, that the rule will not impair the reliability of electric service in the 

state, or that the measures are even technically feasible.

Comment 7: AK - Alaska should not be included in the rulemaking. Explanation provided 

regarding how Alaska is different than other states

Response 7: The EPA is not including emission performance goals for Alaska in this final rule. 

See section VII.F. of the preamble for discussion of this issue.

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

Commenters stated that Alaska should not be included in the proposed 40 CFR 60 Subpart 

UUUU rulemaking. Commenters stated that in the proposed rulemaking, EPA recognizes that 

states differ in important ways, including in their mix of existing EGUs and in their policy 

priorities." Commenters stated that GVEA contends that the differences in Alaska make the 

Clean Power Plan unreasonable, arbitrary, and capricious when applied to Alaska, and 

particularly to GVEA, for at least the reasons discussed below.

Commenters stated that first, Alaska has very little coal generation. Commenters stated that the 

only two coal-fired EGUs included in the rulemaking are Healy Unit 1 and Healy Unit 2. 

Commenters added that all other Alaska Subpart UUUU-affected EGUs are natural gas-fired 

stationary combustion turbines, primarily energy efficient combined-cycle turbines.

Commenters stated that the total heat input of Healy Unit 1 and Healy Unit 2 is 985 MMBtu/hr 

compared to the total heat input of approximately 9,225 MMBtu/hr for all proposed Subpart 

UUUU-affected natural gas-fired EGUs in Alaska. Commenters added that these two coal-fired 

EGUs represent 9.6 percent of the total heat input capacity for all Subpart UUUU-affected EGUs 

in Alaska. Commenters added that the overwhelming majority of proposed Subpart UUUUaffected EGUs in Alaska are energy efficient natural gas-fired combined cycle turbines, making 

an Alaska Plan unnecessary.

Commenters added that second, many assumptions in the proposed rule are simply inapplicable 

to Alaska. Commenters stated that one of these inappropriate assumptions is: "The utility power 
41

sector is unique in that, unlike other sectors where the sources operate independently and on a 

local scale, power sources operate in a complex, interconnected grid system that typically is 

regional in scale."

Commenters stated that unlike the lower 48 states, Alaska is unique because the utility power 

sector is stranded from other states and does not have a complex, interconnected grid system in 

any scale. Commenters added that it is highly unlikely if not impossible for Alaska to participate 

in integrated multi-state compliance strategies to increase the flexibility and cost-saving 

opportunities that would be available to the covered EGUs.

Commenters stated that EPA also offers the following: "A state may demonstrate during the 

comment period that application of one of the building blocks to that state would not be expected 

to produce the level of emission reduction quantified by the EPA because implementation of the 

building block at the levels envisioned by the EPA was technically infeasible or because the 

costs of doing so were significantly higher than projected by the EPA."

Commenters stated that an Alaska Plan would likely have the unintended consequence of 

imposing additional costs on GVEA customers who are already paying higher than average rates 

for electricity. Commenters added that moreover, the EPA proposed heat rate improvement of 6 

percent is technically infeasible for Unit 1 and Healy Unit 2; there are significant transmission 

constraints related to NGCC energy; natural gas resources are not readily available; 

incorporation of additional RE may be difficult and economically infeasible; implementation of 

the rule will result in significant stranded asset; and GVEA members have likely maximized their 

energy efficiency opportunities.

Comment 8: AK - Alaska is unique and should be exempted from the rule or the EPA must 

determine achievable and reasonable emission rate for existing EGUs in Alaska; Alaska's electric 

utility sector lacks interconnectivity

Response 8: The EPA is not including emission performance goals for Alaska in this final rule. 

See section VII.F. of the preamble for discussion of this issue.

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

Commenters argued Alaska has a lack of interconnectivity of their electric grid and that Alaska 

should be exempted from the rule, or EPA must determine an achievable and reasonable 

emission rate for existing EGUs.

Commenters stated for Alaska, implementing the rule is particularly problematic because EPA 

designed the rule for generating units that are interconnected through a robust transmission grid. 

Commenters stated a lack of interconnectivity is the very characteristic that most distinguishes 

Alaska's electric utility sector from the rest of the country. Commenters added because of this 

difference and others, Alaska should be exempted from any final rule limiting CO2 emissions 

from existing EGUs. Commenters stated alternatively, EPA must conduct the necessary analysis 

to determine an achievable and reasonable CO2 emission rate for existing EGUs in Alaska based 

on an accurate factual record.
42

Commenters stated, Alaska's utilities face unique challenges in providing electric service - in 

fact, electric utility service is not universally available. Commenters said, 128 electric utilities 

serve our major population centers and rural communities. Commenters said, the service areas 

for these utilities include over 150 remote, stand-alone electric distribution systems serving 

villages, most of which are inaccessible by road. Commenters said, in these rural locations, 

service is provided by small-generation units that either operate in isolation or are only weakly 

linked to other small electric generation units. 

Commenters stated, in addition to lacking interconnection amongst our electric utility systems, 

they also lack an interconnected road or natural gas pipelines linking our cities, towns and 

villages. Commenters said, in this context, one utility, Alaska Village Electric Corporation, 

serves 54 villages, including Old Harbor and Savonga- communities 734 miles apart. 

Commenters said, another utility, Alaska Power Company, serves 26 communities, including 

Klawock and Tok communities separated by 645 miles. Commenters said, the absence of 

transmission lines to share power among communities and a road or pipeline system to transport 

fuel to remote areas, presents a huge challenge for providing affordable and reliable power to 

rural consumers.

Commenters stated, with some notable exceptions, the power and heating needs for these remote 

areas are met by diesel barged up from lower-48 suppliers or transported from petroleum 

refineries in Nikiski or Valdez, Alaska. Commenters said, after seasonal freeze-up, many remote 

communities must rely on fuel that is stored in local tank farms, or pay a premium for fuel flown 

in by air tankers. Commenters said, when fuel reserves run short in these remote communities, 

truly extraordinary (and expensive) measures may be necessary to ensure the availability of fuel. 

Commenters said, to help communities meet their energy needs the state supports programs to 

maintain fuel tanks, improve power generation and end use efficiency, and exploit local 

renewable energy sources such as wind, biomass, solar, geothermal, and hydroelectric. 

Commenters stated, the provision of electric utility service in Alaska cannot be compared to the 

more densely populated areas of the country. Commenters said, elsewhere in the U.S., most 

electric consumers are connected to an extensive electric grid. Commenters said, these 

interconnected states also have well-established interconnected energy markets that provide for 

the sale and transmission of power from where it can be most economically produced to where 

demand exists. Commenters said, here, other than Anchorage and Matanuska load centers, no 

Alaskan load centers are interconnected by redundant transmission infrastructure. Commenters 

said, Alaskan loads are too small and too distant to support the type of electric transmission grid 

available in the continental U.S.

Comment 9: AK - Alaska is unique, should be exempted from the rule; Alaska's major 

population and electric load centers have limited interconnectivity. 

Response 9: The EPA is not including emission performance goals for Alaska in this final rule. 

See section VII.F. of the preamble for discussion of this issue.
43

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

Commenters argued Alaska's utility sector is fundamentally different from the electric utility 

industry in the continental U.S., and concluded Alaska should be exempted from the rule.

Commenters stated Alaska's electric utility sector differs in many ways from the industry in the 

rest of the United States. Commenters added the utility power sector in the continental U.S., as 

described by EPA, is characterized by the interconnection of a variety generation resources by 

robust transmission grids extending over large regions. Commenters stated the interconnected 

nature of the continental grid enables flexible dispatch of generation resources and renders 

electricity a generally fungible product. Commenters stated the fungible nature of electricity and 

the flexibility in dispatch practices permitted by an interconnected transmission grid are "central, 

to EPA's evaluation of the '"best system of emission reductions." Commenters stated however, 

EPA's description of the utility power sector in the continental U.S., does not describe the 

electric utility sector in Alaska.

Commenters stated Alaska does not have a robust infrastructure of looped transmission facilities 

interconnected with generation facilities extending over large regions. Commenters stated rather, 

as a state, Alaska is "islanded"- it has no interconnection with other states or regions. 

Commenters stated the relatively small population (0.3% of U.S. population) is dispersed over a 

substantial geographic area (16% of U.S. landmass or 570,641 square miles). Commenters added 

transmission lines do link a few major population centers, but these systems have limits. 

Commenters stated because the Proposed Rule relies on a factual premise that does not apply to 

Alaska, the state should be exempted from the rule.

Commenters stated, there are a few larger electric utility load centers in Southeast, Southcentral, 

and Interior Alaska. Commenters said, four of these load centers have limited transmission 

interconnections: the Kenai Peninsula, Anchorage, Matanuska, and Fairbanks load centers. 

Commenters said, because the transmission lines generally follow the 470-mile long Alaska 

Railroad corridor between Seward and Fairbanks, these loosely interconnected electric load 

centers are jointly referred to as the "Railbelt." 

Commenters stated, the Municipality of Anchorage is Alaska's largest population center with 

291,826 people (in 2010) and a land area of 1,705 square miles. Commenters said, our largest 

city is spread over seventy percent more land area than the State of Rhode Island which had a 

population more than three times that of Anchorage in 2010. Commenters said, with a land area 

of 24,608 square miles and a population in 2010 of 88,995, the Matanuska-Susitna Borough is 

larger than ten states, each of which has a population many times larger than the MatanuskaSusitna Borough. Commenters said, even in our "urban" areas, Alaskan utilities have a lot of 

ground to cover to deliver power from generating units to load.

a. Railbelt Utilities

Commenters stated, the Railbelt load centers are served by six vertically integrated, cooperative 

or municipally owned utilities. Commenters said, the Kenai Peninsula is served by Homer 

Electric Association (Homer), the City of Seward, and Chugach Electric Association (Chugach). 

Commenters said, the Anchorage load center is served by Chugach, Anchorage Municipal Light 
44

and Power (ML&P), and Matanuska Electric Association (MEA). Commenters said, MEA also 

serves in the Matanuska load center. Commenters said, Golden Valley Electric Association 

(GVEA) serves the Fairbanks load center Commenters said, each of these independent utilities is 

governed by a locally elected board.

Commenters stated, the Railbelt utilities serve a region of approximately 100,000 square miles, 

approximately half the size of the area served by the Electric Reliability Council of Texas 

(ERCOT). Commenters said, ERCOT provides independent system operator (ISO) service 

through a unified system controlling 43,000 miles of transmission infrastructure and 550 

generation units. Commenters said, by contrast, our Railbelt utilities independently provide 

service in their territories utilizing a total of 1,500 miles of transmission infrastructure and 39 

utility or state owned generation units, plus purchases from a few small independent power 

producers. Commenters said, even if an ISO were created in Railbelt Alaska, it would take a 

substantial investment in infrastructure to have the same system operational flexibility enjoyed 

by ERCOT.

Commenters stated, the Railbelt utilities generate approximately 80% of the state's electricity and 

serve a peak load of around 870 MW. Commenters said, all five of the "likely affected EGUs" 

identified by EPA - Nikiski Cogeneration, George M. Sullivan Plant 2, Beluga Power Plant, 

South-central Power Plant, and Healy Unit 1 - provide electricity within the Railbelt. 

Commenters said, with the exception of transmission between the Anchorage and Matanuska 

load centers, the Railbelt load centers, and thus the affected EGUs, are connected by only single 

contingency outage transmission tie lines. Commenters said, because loss of these single 

contingency lines means no energy can be transported amongst load centers, each utility must 

carry sufficient reserve locally to meet their loads. 

b. Railbelt Transmission Connections

Commenters stated, the Kenai Peninsula load center is connected to the Anchorage load center 

by a 90-mile, single contingency 115kV transmission tie line owned by Chugach. Commenters 

said, the ability to move power on the Kenai to Anchorage transmission line is constrained by a 

stability limit of approximately 70 to 75MW, the need for approximately 10MW of reserve 

capacity, and increased line losses associated with increased energy transfer.

Commenters stated, the Matanuska and Anchorage load centers are connected by multiple 

transmission systems. Commenters said, the first is a 230 kV transmission system owned by 

Chugach. Commenters said, this system connects Chugach's and ML&P's generation plants to 

the Teeland Substation in the western portion of the Matanuska load center. Commenters said, 

the second system is a 115 kV transmission line jointly owned by ML&P, Chugach and MEA. 

Commenters said, this 115kV line connects the Eklutna Hydroelectric Project to the Anchorage 

load center and to the eastern portion of the Matanuska load center. Commenters said, finally, 

MEA owns a 115 kV transmission system that connects the eastern and western portions of the 

Matanuska load center, creating a looped system with the Anchorage load center.

Commenters stated, the Matanuska and Anchorage load centers are connected to the Fairbanks 

load center by a 200-mile, single contingency transmission system currently operated at 138kV 

running from Teeland Substation to Healy. Commenters said, this includes (1) a 6 mile 138kV 
45

line connecting the Teeland and Hollywood substations, which is currently owned by the State 

and due to transfer to MEA in 2018; (2) a 21 mile 115 kV line connecting Hollywood and 

Douglas that is owned by MEA; and (3) the 173-mile Alaska Intertie built to a 345 kV design 

connecting the Douglas and Healy substations and owned by the State. Commenters said, from 

Healy, two 138kV transmission lines carry power to Fairbanks - a 103 mile line running to the 

Goldhill substation and the 97 mile long Northern Intertie running into Wilson Substation. 

Commenters said, while conditions can vary, the Alaska Intertie is typically operated at or near 

its usual stability limit of approximately 70-80 MW throughout the year to deliver electricity 

generated at hydroelectric and natural gas facilities to Fairbanks. Commenters said, energy 

purchases are generally scheduled to the maximum capacity of the line, depending on the 

availability of hydroelectric and gas generation capacity, and the availability of natural gas fuel.

Commenters stated, these transmission lines follow routes that are often remote from all road 

access, and are subject to outages during winter peak loads caused by avalanches and ice 

loading. Commenters said, in particular, the Alaska lntertie has two cables bundled together 

about 8 inches apart for each phase. Commenters said, the snow/ice loading on the lntertie can be 

particularly dramatic when the accumulated snow and ice bridges the gap between the two 

cables. Commenters said, once such a bridge is formed, snow and ice accumulate across the 

entire platform, causing accumulations of more than one-foot diameter. Commenters said, there 

is a particular risk of ground fault when uneven snow loading causes the lines to sag to the 

ground.

Comment 10: AK - Alaska should be exempted from the rule

Response 10: The EPA is not including emission performance goals for Alaska in this final rule. 

See section VII.F. of the preamble for discussion of this issue.

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

Commenters argued Alaska should be exempted from the rule in particular due to Alaska's lack 

of an interconnected grid. The commenters argued attempts to comply with the rule would result 

in extraordinary costs, and may raise reliability concerns.

Commenters stated Alaska should be exempted from any section 111 (d) rule governing carbon 

emissions from EGUs because Alaska's electric utility sector differs in critical respects from the 

industry in the continental U.S. Commenters added perhaps most significantly, Alaska does not 

have a robust interconnected grid. Commenters stated because of the lack of transmission 

interconnections and other unique circumstances, Alaska cannot reasonably implement the 

BSER measures. Commenters stated however, Alaska is already achieving carbon emission 

savings pursuant to our own policies without federal intervention.

Commenters stated it bears noting that even the primary policy motivation for this rule - the 

finding that fossil fuel-fired EGUs are the largest emitters of GHGs among stationary sources in 

the U.S. - does not apply to Alaska. Commenters stated nationally, power plants account for 

roughly one-third of all domestic GHG emissions. Commenters stated EPA reports that, in 2005, 

sources in the U.S. emitted 7,195.3 million metric tons (MMT) of CO2e. Commenters added of 
46

that, emissions from the electric power industry accounted for 2A45. 7 MMT- slightly more than 

one-third of U.S. CO2e emissions. Commenters stated by comparison, in 2005, electric 

generation in Alaska produced 3.2 MMT CO2e- only 6 percent of the state's total 52.1 MMT 

CO2e emissions. Commenters stated by our count, the five "likely affected fossil sources" in 

Alaska accounted for only 4.4% of statewide GHG emissions. Commenters added these

emissions are de minimus in the context of the issue EPA seeks to address in this rulemaking. 

Commenters stated the policy rational behind the Clean Power Plan's focus on the electric utility 

sector does not apply to Alaska.

Commenters stated while the opportunity to reduce CO2 emissions from Alaska's electric utility 

sector is negligible, attempts to comply with the Proposed Rule would result in extraordinary 

costs. Commenters stated implementing the Proposed Rule may also raise issues regarding the 

reliability of electric service, and may result in irrational consequences - including greater 

impairment to air quality in Fairbanks. Commenters concluded this rule should not be applied in 

Alaska.

Comment 11: AK - Alaska has special considerations affecting generation and delivery of 

electric power

Response 11: The EPA is not including emission performance goals for Alaska in this final rule. 

See section VII.F. of the preamble for discussion of this issue.

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

Commenters stated that many special considerations affect generation and delivery of electric 

power in Alaska, particularly for GVEA. Commenters that the GVEA service area is located in 

Interior Alaska. Commenters said in a climate which drops to 50 degrees below zero, having 

reliable generation is imperative, truly a matter of life and death. Commenters expounded that 

available fuel is restricted in the Interior largely to naphtha, diesel, and coal. Commenters added 

that reasonably priced or low cost liquid fuel has rarely been available, a cost issue that has been 

exacerbated with the closure of the Flint Hills Resources (FHR) refinery at North Pole, Alaska in 

2014. Commenters stated that this closure has also increased the vulnerability of the liquid fuel 

supply chain to interruption. Commenters stated that given this increased vulnerability and the 

high cost, additional oil-fired EGUs are not an appropriate option for compliance with Subpart 

UUUU. Commenters added that local natural gas resources do not exist in the region and no 

natural gas pipeline to Interior Alaska exists. Commenters stated that natural gas would need to 

be liquefied and trucked into the Interior from significantly distant locations. Commenters stated 

that as a result, installing cost effective natural gas-fired generation is not an option at this time.

Commenters stated that unlike the lower 48 states, Alaska is stranded from inter-state 

transmission grids. Commenters added that Alaska is electrically isolated from the lower-48 

states and the nearest neighbor, Canada. Commenters stated that one constrained transmission 

system, the Railbelt Grid, exists. Commenters stated that The Railbelt Grid provides limited 

interconnection within the most populated region of the state. Commenters stated that currently, 

GVEA typically maximizes the capabilities of the existing transmission system. Commenters
47

added that additional transmission of power from Southcentral Alaska to the Interior is not an 

option without significant costly upgrades. Commenters stated that transmission is limited to a 

single 80 megawatt (MW) transmission line between Anchorage and Healy where the line 

bifurcates into two lines, both serving the GVEA service area. Commenters added that in 

addition, in the past, the purchase of energy from Southcentral utilities has been limited during 

the winter months due to limited gas supplies in extreme cold weather. Commenters concluded 

that regardless of the availability of power from Southcentral utilities, the transmission 

infrastructure between Southcentral Alaska and the Interior cannot support the transmission of 

additional energy.

Comment 12: AK - Alaska's regulatory framework is different; utilities may choose to be 

exempt from economic regulations, and no wholesale power market exists

Response 12: The EPA is not including emission performance goals for Alaska in this final rule. 

See section VII.F. of the preamble for discussion of this issue.

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

Commenters argued Alaska's regulatory framework is different from that presumed by EPA. The 

commenters argued Alaska utilities may choose to be exempt from economic regulation, and no 

organized wholesale power market exists.

Regulatory framework. Commenters stated Alaska's regulatory environment differs from the 

framework presumed by EPA. Commenters stated in the continental U.S., FERC regulates 

interstate electric energy transmission and the wholesale energy market. Commenters added 

however, because Alaska has no interstate electric energy transmission, Alaskan utilities are 

largely unaffected by FERC transmission and wholesale market rules. Commenters stated 

instead, wholesale transactions between utilities are regulated by the public utility commission, 

the Regulatory Commission of Alaska (RCA).

Commenters stated the RCA regulates electric utilities according to traditional economic 

ratemaking principles - requiring that reliable service is provided at just, reasonable, 

nondiscriminatory rates. Commenters stated utilities, under RCA oversight, must apportion 

charges to their respective customer classes according to the "cost causer-cost payer" principle. 

Commenters stated the RCA and the Alaska Energy Authority (AEA), through the Intertie 

Management Committee, may implement reliability standards.

RCA's statutory authority. Commenters stated there are limits to the RCA's statutory authority. 

Commenters added unlike public utility commissions in many other states, the RCA does not 

have general facility siting authority. Commenters expounded also, while other states have 

enforceable resource plans, in Alaska, utilities submit 10-year capital improvement plans for 

informational purposes only. Commenters concluded significantly, municipal and cooperative 

utilities, including all of the utilities affected by this rule, may choose to be altogether exempt 

from economic regulation by the RCA.
48

No RTOs or ISOs. Commenters stated nor is the limited Alaska transmission system managed by 

a Regional Transmission Organization or ISO as is typical elsewhere in the country. Commenters

stated here, individual electric utilities or state agencies own discrete portions of the transmission 

infrastructure. Commenters stated each utility operates the transmission infrastructure it owns 

and, in some cases, operates transmission infrastructure owned by the State under contract. 

Commenters added interconnection agreements exist, if at all, only when each of the 

participating utilities find the terms of the agreement to be in their individual members or 

customers best interests.

No wholesale power market. Commenters stated no organized wholesale power market exists in 

Alaska. Commenters added instead, wholesale power transactions between utilities are based 

upon bilateral agreements, and typically involve hour-ahead non-firm economy energy 

transactions. Commenters stated existing transmission system limitations prevent most Alaska 

utilities from entering into firm wholesale power transactions. Commenters stated by contrast,

within the interconnected continental grid, power can be bought on a firm or non-firm basis, and 

for varying blocks of time.

Commenters stated although outlined in AS 44.99.115, Alaska's energy policy is not integrated 

in a single statute. Commenters added the policies are integrated through multiple statutes that 

establish and allocate duties and authority amongst numerous state departments and agencies, 

including AEA, DEC and the RCA.

Comment 13: AK - Installing natural gas-fired EGUs in not an option at this time

Response 13: The EPA is not including emission performance goals for Alaska in this final rule. 

See section VII.F. of the preamble for discussion of this issue.

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

Commenters stated that the GVEA service area is located in Interior Alaska, centered in 

Fairbanks. Commenters stated that local natural gas resources do not exist in the region and a gas 

pipeline from the Alaska North Slope or Cook Inlet fields has not been installed. Commenters

concluded that as a result, installing natural gas-fired generation is not an option at this time.

Commenters expounded that the construction of a natural gas pipeline from the Alaska North 

Slope to a deepwater terminal in Southcentral Alaska is currently being evaluated by the State of 

Alaska and a consortium of companies consisting of Exxon Mobil, ConocoPhillips, BP, and 

TransCanada. Commenters added that this potential project is in the very early stages of 

evaluation. Commenters stated that the primary purpose of this project would be the export of 

liquefied natural gas (LNG) to markets outside of Alaska. Commenters added that a secondary 

benefit of the project would be that natural gas would become available to Interior Alaska.

Commenters stated that whether a natural gas pipeline will be constructed and the date that 

natural gas might become available in Interior Alaska cannot be determined at this time. 

Commenters added that past attempts to construct a pipeline have failed. Commenters concluded 
49

that as a result, the state of Alaska cannot rely on natural gas-fired electrical generation in 

Interior Alaska to replace any of the coal fired-generation of the Healy Power Plant.

Comment 14: AK - Existing infrastructure cannot support transmission of electricity and 

reliance on transmission would increase the reliability risk.

Response 14: The EPA is not including emission performance goals for Alaska in this final rule. 

See section VII.F. of the preamble for discussion of this issue.

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

Commenters stated that transmission of additional power from Southcentral Alaska is not a 

viable option. Commenters added that adequate natural gas supplies may become available from 

the Cook Inlet gas fields to enable additional natural-gas power generation in Southcentral for 

potential transmission to Interior. Commenters added that however, the existing transmission 

infrastructure between Southcentral Alaska and Interior Alaska cannot support the transmission 

of electricity from any additional Southcentral generation that might be intended to displace 

Interior coal-fired generation. Commenters stated that the estimated cost to upgrade the 

transmission infrastructure from Anchorage to Fairbanks is approximately $500,000,000. 

Commenters added that the total estimated cost to fully upgrade the entire Railbelt Grid to enable 

additional NGCC transmission from Southcentral and for unencumbered utilization of existing 

and possible new RE generation is approximately $1,000,000,000. Commenters stated that 

because of the isolated nature of Interior Alaska, GVEA customers are already paying for 

electricity at rates that are much higher than Southcentral Alaska and most of the lower 48 states. 

Commenters concluded that the limited GVEA customer base simply cannot afford the added 

cost of the required transmission infrastructure.

Commenters added that independent of cost, reliance on transmission of electrical power from 

outside of Interior Alaska introduces increased reliability risk to GVEA customers due the 

extreme climatic and geographical conditions previously described. Commenters concluded that 

because of the need to protect the health and safety of GVEA customers, primarily relying on 

electrical transmission from Southcentral Alaska is not an acceptable alternative to having 

electrical generation in Interior Alaska.

Comment 15: AK - Reliance on transmission from outside the interior increases reliability risk

Response 15: The EPA is not including emission performance goals for Alaska in this final rule. 

See section VII.F. of the preamble for discussion of this issue.

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

Commenters stated that reliance on transmission of electrical power from outside of the Interior 

introduces increased reliability risk to GVEA members. Commenters added that GVEA must 

have the ability to supply electricity to the Interior 365 days a year, particularly during the winter 
50

to protect against the loss of life and destruction of property under extreme climate conditions 

and deliver the power despite system upsets and malfunctions. Commenters added that any 

electrical transmission line from Southcentral Alaska to the Interior must navigate the mountains 

of the Alaska Range and hundreds of miles of rugged, remote areas. Commenters added that 

repair and maintenance of this remote line is challenging at best. Commenters stated that given 

the climate and rugged territory, particularly in the winter months, it is not prudent or acceptable 

for GVEA members to rely primarily or exclusively on electrical transmission from Southcentral 

Alaska.

Commenters added that the Interior lacks economically viable renewable resources. Commenters

stated that GVEA has already developed one of the more practicable RE resources, installing 

approximately 25 MW of wind generation near Eva Creek. Commenters stated that GVEA is 

currently evaluating the Eva Creek windpower units to determine whether the equipment will 

withstand sub-arctic climate conditions and produce power at predicted rates. Commenters stated 

that even if the wind-power units are successful, these units and other renewable resources 

cannot displace Units 1 and 2 at the Healy Power Plant as essential baseload units.

Comment 16: AK - HRI of 6% cannot be achieved at the Healy Power Plant; Healy Unit 2 was 

ignored in the baseline and goal calculations; equipment upgrades were based on magnitude of 

larger units.

Response 16: The EPA is not including emission performance goals for Alaska in this final rule. 

See section VII.F. of the preamble for discussion of this issue. 

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

Commenters argued that heat rate improvements of six percent cannot be achieved at the Healy 

Power Plant. The commenters also argued that Healy Unit 2 was ignored in the baseline and goal 

calculations, and that EPA's analysis of equipment upgrades relied on units that were a 

magnitude larger than the Healy units. The commenters also argued application of the rule would 

result in extraordinary costs, impair reliability, and aggravate air quality concerns in the 

Fairbanks area.

Commenters stated the first BSER measure proposed by EPA is a six percent heat rate 

improvement (HRI) at coal-fired steam generating units. Commenters stated EPA evaluated two 

general approaches to improving heat rates: (1) implementing "best practices" in operations and 

maintenance and (2) equipment upgrades. Commenters stated applying this building block to 

Alaska, EPA assumed a six percent reduction in the CO2 emission rate at Healy Unit 1 - from 

2,852 to 2,681lb/MWh. Commenters stated this element of the goal calculation is not reasonable 

as applied to Alaska.

Commenters stated first, as EPA recognizes, heat rate improvements may be accomplished 

through the use of "best practices" or equipment upgrades only to the extent those measures have 

not already been implemented at a facility. Commenters added however, although EPA applies 

this element to Healy Unit 1 in the goal calculation, the agency does not provide information to 
51

support a determination that "best practices" or equipment upgrades are available to that EGU. 

Commenters added worse, the baseline and goal calculations ignore Healy Unit 2 altogether.

Commenters stated second, EPA's analysis of equipment upgrades relies on Sargent & Lundy 

(2009), a study that evaluated HRI at coal units between 200 MW and 900MW. Commenters

stated the units evaluated in that report are an order of magnitude larger than the 27 and 52.5MW 

Healy units. Commenters added without closer study, EPA cannot reasonably conclude that the 

same equipment upgrades evaluated for those large units are technically feasible for the Healy 

units. Commenters stated even if some of the equipment upgrades are technically feasible, EPA 

failed to support a conclusion that those upgrades otherwise qualify as BSER for small coal 

EGUs.

Commenters stated the only information currently available reveals that a six percent HRI cannot 

be achieved by the Healy units. Commenters stated GVEA reports that a number of the HRI 

measures recommended by EPA have already been implemented at the coal plant and some are 

not available to the Healy units. Commenters stated GVEA's initial evaluation suggested that 

heat rate improvements of 2.11% and 2.15% might be achievable at Healy Unit 1 and Unit 2, 

respectively. Commenters stated although, given variability in operating conditions, application 

of these measures would not necessarily result in the forecasted improvement as compared to the 

2012 baseline.

Commenters stated installation of pollution control technologies, as required by a consent decree 

with EPA will reverse these gains. Commenters expounded the consent decree requires GVEA to 

install (1) selective catalytic reduction (SCR) equipment at Unit 2; selective non-catalytic 

reduction (SNCR) controls at Unit 1; and (3) SCR controls at Unit 1. Commenters stated GVEA 

anticipates that the SNCR equipment will degrade the heat rate of Healy Unit I by about 0.1% 

and that the installation of SCR equipment will result in a 2.87% degradation of the heat rate at 

each unit. Commenters concluded thus, there are no net heat rate improvements possible in 

Alaska and application of this measure to determine Alaska's goal is unreasonable.

Comment 17: AK - Healy Unit 2 should be an affected EGU and included in baseline data for 

Alaska; GVEA provides emission rate values

Response 17: The EPA is not including emission performance goals for Alaska in this final rule. 

See section VII.F. of the preamble for discussion of this issue. 

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

Commenters stated that Healy Unit 2 formerly known as the Healy Clean Coal Project was either 

inadvertently omitted or impermissibly excluded from the Alaska CO2 Performance Goals 

calculation. Commenters expounded that Healy Unit 2, constructed in 1997 as a Department of 

Energy Demonstration Project, is a coal-fired steam generating unit, and meets all of the criteria 

in proposed 40 CFR 60.5795(b)(1) for classification as an affected EGU. Commenters added that 

Healy Unit 2 was permitted and has maintained its operating permits since 1993, and is currently 
52

permitted under a Title V federal operating permit. Commenters stated that emissions from 

Healy Unit 2 have been included in the State of Alaska emissions inventory since the unit began 

operations in 1998-993 and throughout the warm lay-up period beginning in 2000. Commenters

stated that Healy Unit 2 was maintained in warm lay-up status at expenditures that exceeded $20 

million while contract disputes between the owner and operator, as well as, regulatory issues 

were being resolved. Commenters added that in November 2012, GVEA, in good faith, entered 

into a Consent Decree with EPA and agreed to meet select emission limits and install state-ofthe-art additional emission control equipment on Healy Unit 1 and Healy Unit 2 to bring Healy 

Unit 2 from warm layup into full service. Commenters stated that in the Consent Decree, EPA 

contemplated and authorized the future operation of Healy Unit 2 pursuant to the terms of the 

Consent Decree, resolving EPA objections to the GVEA and the Alaska Industrial Development 

and Export Agency's (AIDEA) intent to restart Unit 2 and operate the Unit for its full service 

life. Commenters stated that the Consent Decree does not contemplate the retirement of Healy 

Unit 2. Commenters added that the Consent Decrees does contemplate EPA's ability to rely on 

the enforceable conditions in the Consent Decree in the future concerning operations of Healy 

Unit 2, including the Alaska Regional Haze SIP. Commenters concluded that EPA contemplated 

the operation of Healy Unit 2 well into the future.

Commenters stated that GVEA is currently investing approximately $187,000,000, excluding 

capitalized interest, in Healy Unit 1 and Healy Unit 2 based on successfully executing the 

Consent Decree with EPA that resolved uncertainties about the future operation of these two 

small steam generating units. Commenters stated that a significant portion of this investment is 

for installation of mandated air pollutant emission controls as agreed to with EPA under the 

executed Consent Decree. Commenters stated that this investment will enable Healy Unit 2 to 

operate at air pollutant emission rates lower than originally designed and in compliance with the 

more stringent rates set forth in the Consent Decree. Commenters added that Healy Unit 2 will 

be operational in a matter of months.

Commenters stated that consistent with the intent to return Healy Unit 2 to full service as agreed 

in good faith with EPA in the Consent Decree, and the fact that Healy Unit 2 has consistently 

been included in the Alaska SIP, GVEA asserts that Healy Unit 2 should be included in the 

Alaska CO2 Performance Goals calculations consistent with other EPA decisions in calculating 

CO2 Performance Goals. Commenters stated that EPA has added estimates for other EGUs not 

yet in operation in 2012 that are affected EGUs for purposes of the emission guideline, 

"including nuclear facilities under construction." Commenters stated that the proposed rule, 

therefore, inadvertently or impermissibly omits Healy Unit 2 when compiling baseline data and 

generating the Alaska CO2 Performance Goals.

Commenters stated that if Healy Unit 2 is not included in the Alaska Performance Goals, the 

goals will simply be unachievable and Healy Unit 2 will not be able to operate in the manner 

contemplated by the parties and relied upon by GVEA in the executed Consent Decree. 

Commenters added that Healy Unit 2 CO2 emissions do not have to be based on 2012 actual 

electrical generation and actual CO2 emissions. Commenters stated that instead, the Healy Unit 2 

electrical generation and CO2 emissions for the purpose of calculating Performance Goals 

should be calculated assuming that Healy Unit 2 was operating as intended. Commenters added 

that given that Healy Unit 2 was and is intended to be a base load unit with an estimated capacity 
53

factor of 85 percent, a reasonable basis for the calculations is that Healy Unit 2 would have 

operated 7,446 hours in 2012.

Commenters summarized that Healy Unit 2 is expected to have a CO2 emission rate of 

approximately 139,800 pounds per hour (lb/hr) at maximum capacity and is expected to have a 

net output of 52.5 MW after the installation of selective catalytic reduction for NOx emission 

control. Commenters stated that the total net MWh would have been approximately 390,915 

MWh. Commenters stated that based on these specifications, the 2012 Healy Unit 2 CO2 

emission rate would be approximately 2,666 pounds per net megawatt-hour (lb/net MWh) and 

the total Healy Unit 2 CO2 emissions would be approximately 521 ,032 short tons in 2012. 

Commenters concluded that EPA should use these values for correcting the Alaska CO2 

Performance Goals.

Comment 18: AK - Affected EGU inventory is inaccurate; provided corrections

Response 18: The EPA is not including emission performance goals for Alaska in this final rule. 

See section VII.F. of the preamble for discussion of this issue. 

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

Commenters stated that the affected EGU inventory that was used to calculate the Alaska ratebased carbon dioxide (CO2) emission performance goals is inaccurate and provided corrections.

Commenters stated that corrections should be made prior to calculating the final Alaska 

performance goals Commenters stated that this goal recalculation is incomplete and must be 

updated by EPA to incorporate additional information. 

Commenters stated that Unit 8 at the Chugach Electric Association (Chugach Electric) Beluga 

Plant should not be listed as a separate affected EGU. Commenters expounded: Unit 8 is a nonfired heat recovery steam generator (HRSG) associated with the natural gas-fired stationary 

combustion turbines that the U.S. Environmental Protection Agency (EPA) has designated 

Beluga Units 6 and 7. Commenters explained that in other words, Beluga Units 6 and 7 are 

combined-cycle turbines that share the Unit 8 HRSG. Commenters stated that the power 

generated by Unit 8 should be included with the power generated by Beluga Units 6 and 7 to 

accurately represent the combined-cycle turbine electrical generation of these EGUs. 

Commenters stated that Emission Unit 2 at the Golden Valley Electric Association (GVEA) 

Healy Plant was existing in 2012, but was not included in EPA affected EGU inventory; Healy 

Unit 2 and its calculated 2012 emissions should be added to the affected EGU inventory and 

Alaska CO2 Performance Goal. 

Commenters stated that Unit 6 at the Anchorage Municipal Light & Power (ML&P) George M. 

Sullivan Plant 2 is a non-fired HRSG associated with stationary combustion turbines that EPA 

has designated Units 5 and 7. Commenters added that in other words, Plant 2 Units 5 and 7 are 

combined-cycle turbines that in 2012 shared the Unit 6 HRSG; the power generated by Unit 6 

should be included with the power generated by Plant 2 Units 5 and 7 to accurately represent the 
54

combined-cycle turbine electrical generation of these EGUs. Commenters noted that Unit 5 was 

converted to a simple-cycle turbine in 2013, but was operated as a combined-cycle turbine in 

2012.

Commenters stated that two additional natural gas-fired combined-cycle combustion turbines 

were under construction at ML&P Plant 2 in 2013, but were not included in the EPA "Under 

Construction" Calculation; these two units should be added to the affected EGU inventory. 

Commenters stated that the Chugach Electric South-central Power Project Unit 4 (EPA EU ID 4) 

has not yet commenced construction and so should be eliminated from the affected EGU 

inventory. 

Commenters stated that for some EGUs, the reported CO2 emissions that EPA used in the 

Alaska CO2 Performance Goals calculations were based on 40 CFR 98 Subpart C calculation

methods. Commenters added that in other cases, EPA used the U.S. Energy Information 

Administration (EIA) 923 and 861 reports to calculate CO2 emissions for each unit. Commenters

explained that the CO2 emissions that were calculated based on data contained in the EIA reports 

are frequently different than the CO2 emissions reported under 40 CFR 98 because of different 

calculation methodologies and because the emissions are calculated for different purposes.

Commenters summarized that EPA should only use the established CO2 emission factors from 

40 CFR 98 to ensure goal calculation and enforcement consistency. Commenters stated that for 

example, CO2 emissions determined using continuous emission monitoring systems (CEMS) can 

be different than CO2 emissions determined using 40 CFR 98; the difference could lead to 

inadvertent reporting inconsistencies and false indications that compliance with the plan 

requirements is not being attained. Commenters concluded that consistently using CO2 emission 

factors from 40 CFR 98 for all purposes would eliminate this risk. 

Commenters stated that GVEA Healy Unit 2 was constructed in 1997 as a Department of Energy 

Demonstration Project, is a coal-fired steam generating unit, and meets all of the criteria in 

proposed 40 CFR 60.5795(b)(1) for classification as an affected EGU. Commenters stated that 

Healy Unit 2 was operated in 1998 and 1999, but has not generated electricity since then due to 

disagreement amongst the parties, including regulatory agencies. Commenters added that in 

November 2012, GVEA entered into a Consent Decree with EPA in good faith and agreed to 

meet select emission limits and install additional emission control equipment on Healy Unit 1 

and Healy Unit 2 to enable returning Healy Unit 2 to service. Commenters stated that GVEA is 

currently investing approximately $187,000,000, excluding capitalized interest, in Healy Unit 1 

and Healy Unit 2 based on successfully executing this Consent Decree with EPA that resolved 

uncertainties about the future operation of these two steam generating units; this investment will 

enable Healy 2 to operate at air pollutant emission rates equal to or lower than the emission rates 

that had originally been expected. Commenters concluded that consistent with the intent to return 

Healy Unit 2 to service as agreed in good faith with EPA in the Consent Decree, APA believes 

that Healy Unit 2 should be included in the Alaska Performance Goals calculations. Commenters

added that if Unit 2 is not included in the Alaska Performance Goals, the goal will be too low 

and the Unit will not be able to operate as expected which is counter to that agreed upon in the 

EPA-endorsed Consent Decree. Commenters stated that including Healy Unit 2 in the 

performance goals calculations cannot reasonably be based on 2012 actual electrical generation 
55

and actual CO2 emissions because the unit was not operating in 2012. Commenters stated that 

instead, the Healy Unit 2 electrical generation and CO2 emissions for the purpose of calculating 

performance goals should be calculated assuming that Healy Unit 2 was operating as intended.

Comment 19: AK - Alaska's goals are based on unrealistic assumptions, are unclear, and are 

based on an inaccurate EGU inventory

Response 19: The EPA is not including emission performance goals for Alaska in this final rule. 

See section VII.F. of the preamble for discussion of this issue.

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

Commenters stated that incomplete, corrected calculations have been prepared by the EPA. 

Commenters stated that these updated calculations are incomplete because EPA did not provide 

adequate information to determine the basis for several calculation steps. Commenters added that 

even so, these incomplete, corrected calculations demonstrate that the recalculated interim CO2 

performance goal for Alaska should be no less than 1,261 pounds of CO2 per net megawatt-hour 

(lb CO2/net MWh) compared to the proposed EPA interim goal of 1,097 lb CO2/ net MWh. 

Commenters stated that the same incomplete, corrected calculations demonstrate that the final 

CO2 performance goal for Alaska should be no less than 1,191 lb CO2/net MWh compared to 

the proposed EPA final goal of 1,003 lb CO2/net MWh. Commenters concluded that the 

completely corrected calculations will likely result in higher goals.

Commenters stated that the corrections that were made and the reasons that EPA must update the 

calculations before identifying interim and final Alaska CO2 Performance Goals are summarized 

below.

• Step 2- Building Block 1: Commenters stated that the APA calculations use a 

more realistic heat rate improvement of one percent for the two Healy coal-fired 

EGUs, as opposed to the six percent that EPA assumes.

• Step 3a- Building Block 2: Commenters stated that both the APA and EPA 

calculations assume that electricity generated by natural gas-fired combined-cycle 

combustion turbines will be redispatched to offset generation from existing coalfired EGUs. Commenters added that the reality today is that the existing 

transmission capacity between Southcentral Alaska and Interior Alaska is 

restricted, so limited opportunity exists to offset the generation from coal-fired 

EGUs. Commenters stated that the APA calculations conservatively retain the 

redispatched generation, but EPA should carefully examine whether redispatch is 

a viable option in Alaska before recalculating the goals and promulgating a final 

rule.

• Step 4b- Building Block 3: Commenters stated that EPA applies a renewable 

electricity growth factor of 11.426 percent to each year between 2020 and 2029. 

Commenters added that this growth rate is based upon data EPA complied for 
56

2002 through 2012, but EPA did not provide the data or the calculations that were 

used to determine the 11.426 percent factor. Commenters stated that this growth 

factor is too high, but cannot further identify the reason the factor is high without 

reviewing the EPA calculations. Commenters stated that the updated but 

incomplete APA goal calculations use the EPA growth factor despite the lack of 

technical justification for the factor. Commenters added that EPA should 

reexamine this growth factor to determine if the factor is realistic and should 

share the results of this reexamination with the public before recalculating the 

goals and promulgating a final rule.

• Step 5- Building Block 4: Commenters stated that EPA provided no support for 

the demand side energy efficiency potential for the years 2020 through 2029. 

Commenters stated, Commenters do not believe that significant reductions in 

demand are available in Alaska through energy efficiency. Commenters added 

that the updated but incomplete APA goal calculations do not include a demand 

side energy efficiency factor for this reason. Commenters stated that EPA should 

reexamine the energy efficiency factors that the agency used to determine if the 

factors are realistic and should share the results of this reexamination with the 

public before recalculating the goals and promulgating a final rule.

Commenters added that GVEA is a member of the APA and endorses the APA comments 

addressing the proposed Subpart UUUU rule.

Commenters said that, significant changes in Alaska's generation mix would be required to 

achieve the assigned emission rate. Commenters said that Alaska's compliance options would be 

very limited including the premature retirement of at least one coal plant. Commenters said this 

shutdown could cause an unreasonable expense to ratepayers. Commenters said EPA's goal also 

assumes Alaska can mandate consumer energy efficiency practices with the impact of avoiding 

744 GWh of generation (almost a quarter of the total generation from "affected EGUs" in 2012 

and perhaps a third of "affected EGU" generation in 2030). Commenters said the small 

population and limited electric utility infrastructure render the EPA's hypothetical compliance 

strategies impossible to implement at a cost that provides affordable and reliable essential 

electric utility service to Alaska ratepayers.

Comment 20: AK - BB3 RE

Response 20: The EPA is not including emission performance goals for Alaska in this final rule. 

See section VII.F. of the preamble for discussion of this issue.

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

Commenters stated that additional production of significant electricity from renewable energy 

sources is not a likely or realistic option. Commenters stated that approximately 140,000 MWh 

of non-firm renewable energy has already been incorporated into the GVEA generation portfolio. 

Commenters stated that incorporating additional generation from renewable energy sources is 
57

theoretically possible depending on type, size, and location, but integration and interconnect 

costs may be completely uneconomical. Commenters added that the transmission grid location is 

limited, so the need for additional infrastructure is generally considered a precursor to further 

renewable energy development. Commenters stated that given this situation and the limited 

population in the GVEA service area, the Alaska Annual RE Growth Factor should be assumed 

to be zero. Commenters stated that reliability is required and paramount due to the extreme 

Alaska climatic conditions. Commenters concluded that reliability cannot be sacrificed in an 

attempt to meet the State's renewable energy goal.

Commenters stated the Alaska Annual RE Growth Factor was calculated differently from the 

factor that was calculated for the Lower 48; for the Lower 48, EPA determined the amount of RE 

generation that is necessary for each region to reach the assigned target. Commenters said using 

that value, EPA determined a constant RE generation growth rate necessary to achieve that goal 

if applied from 2017 through 2029. Commenters said for Alaska, EPA determined the difference 

in the RE generation between 2002 and 2012; the EPA then assumed that this RE generation 

growth rate could be sustained from 2017 through 2029. Commenters said this assumption is 

likely incorrect because EPA has no technical basis for assuming that RE generation growth will 

continue; EPA should assume no growth in RE generation unless EPA can identify RE 

generation projects that will be constructed or specific requirements that will lead to the 

construction of RE generation. 

Commenters stated all of Alaska's affected EGUs are in a specific interconnected region, the 

Railbelt, yet EPA used statewide RE generation as a factor in calculating the Alaska CO2 

Performance Goals. Commenters said Alaska has numerous RE generation projects in remote 

communities that are not connected to the affected EGU electrical grid; this approach results in 

the Alaska CO2 Performance Goals being artificially low. Commenters said the calculation 

should be revised to only include Railbelt region RE projects; in addition, in a small 

interconnected system, like the Railbelt, wind regulation is a challenge and EPA cannot assume 

more projects can be added. 

Comment 21: AZ-goals: provide AZ with no flexibility and are unworkable; will be 

devastating; unequal and disproportionate burden on AZ

Response 21: In this final CPP, the EPA has switched to a regional treatment of building blocks 

which result in a different state goal for Arizona. The regionalization approach to building block 

two in particular means that the reduction potential from the Arizona NGCC fleet is assessed 

regionally instead of being focused in state which seemed to be the root of Arizona’s concern. 

EPA has also revisited the deployment path of its building blocks and the differential between 

Arizona’s interim and final goal provides more flexibility for a glidepath than the interim and 

final rates for the state at proposal. EPA analysis does not suggest that the coal fleet operates in 

a peaking fashion when complying with the final CPP BSER. See sections VI and VII of the 

final rule preamble of the CPP for the EPA’s response to this comment and the CO2 Emission 

Performance Rate and Goal Computation TSD for CPP Final Rule supporting the final 

CPP. Also, see the EPA’s Regulatory Impact Analysis for the Clean Power Plan Final Rule, 
58

EPA-452/R-15-003 (RIA) analysis and power sector modeling for an indication of expected 

system-wide and regional impacts.

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

Commenters said that the EPA's interim and final goals provide Arizona with no flexibility and 

are unworkable. Commenters said that Arizona is left without an effective way to use flexibility 

between the building blocks to achieve the proposed Arizona goals, in particular that witching 

from coal to natural gas by 2020 is the only building block available to Arizona to meet EPA's 

proposed goal.

Commenters stated that the Arizona DEQ analyzed increasing RE and EE standards in the state 

to allow for the continued operation of a portion of the coal-fired fleet in Arizona and, in fact, 

these actions have the opposite effect. Commenters stated that in the ADEQ comments to EPA, 

the State postulated various scenarios of increasing the incremental contribution from RE and EE 

so as to reduce the amount of re-dispatch from coal to NGCC in order to preserve some coalfired generation in the state. Commenters stated that when ADEQ performed this analysis they 

discovered the more Arizona relies on BB3 and BB4 to achieve compliance with the final goal of 

702 lbs CO2/MWh, the farther it gets from compliance with the interim goal (scenarios 2-4). 

Commenters stated that conversely, if Arizona designs its program to comply with the interim 

goal, it ends up with a final rate that is far lower than necessary to comply with the final standard 

and ends up preserving a much smaller portion of its existing coal-fired generation resources. 

Commenters stated that because of all the technical issues associated with the re-dispatch of 

coal-fired generation to NGCC units by 2020, Arizona is faced with insurmountable challenges 

in meeting the proposed interim goals.

Commenters stated that EPA also suggested that Arizona's coal-fired units could be operated as 

peaking plants to cover the peak energy demand during the summer months. Commenters

determined that while such an option may be available at facilities that have a variety of EGUs 

that are co-located and can combust different fuels, the majority of the generating stations with 

coal-fired EGUs in Arizona only have coal-fired units. Commenters stated that therefore, 

operating the Arizona coal-fired EGUs only during the summer months is unrealistic from an 

economic perspective; it is not economically justified to keep a full operating complement on site 

for only several months of plant operation during the year.

Commenters said that while the EPA's Proposed Carbon Rule gives some states considerable 

flexibility to meet their goals, this is not true for Arizona. Commenters said this lack of 

flexibility would result in closure of all coal plants in Arizona by 2020, a goal that is simply 

impossible to meet while maintaining the reliability of the electric system.

Commenters said that Arizona has no flexibility to shift from one building block to another to 

meet its rate-based goal under the program as proposed. Commenters said that if even small 

amounts of coal generation are preserved post 2020 to serve summer peak loads, the interim goal 

cannot be met, and this is true even if Arizona substantially increases reliance on Building 

Blocks 3 and/or 4 above the levels already assumed by the EPA in setting Arizona's goal. 

Commenters stated that if no coal generation remains in 2020, using Building Block 1 will 

obviously have no effect on Arizona's rate (and it would not in any event). Commenters said 
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further, Arizona cannot increase reliance on Building Block 2 because the interim goal 

effectively requires the maximum redispatch possible.

Commenters indicated that the interim and final goals proposed for Arizona will be devastating.

Commenters said that the EPA's calculation of interim and final goals is based on the premise 

that all existing coal-fired EGUs, including Apache Station's ST2 and ST3, are redispatched to 

NGCC, and that Apache Station's existing natural-gas fired steam unit, ST1, is redispatched to 

NGCC. Commenters indicated that AEPCO has no NGCC generating capacity and redispatch of 

ST2, ST3 and ST1 reduces Apache Generating Station's capacity from net installed 555 MW to 

135 MW. Commenters indicated this decrease in generating capacity would be devastating.

Commenters stated that any belief that Arizona would be able to meet the proposed carbon 

emission goals without a large re-dispatch of coal-fired generation to NGCCs is simply 

credulous. Commenters stated that the re-dispatch of all of Arizona's coal-fired generation to 

NGCC units is fraught with insurmountable technical difficulties, especially within the interim 

period. Commenters stated that even if such an outcome could eventually be achieved, the result 

leaves the state's electric energy supply system vulnerable due to a diminished fuel mix and will 

substantially increase energy costs to Arizona customers due to having to construct the necessary 

supporting infrastructure. Commenters stated that technical issues include the inability to meet 

load demands during summer peak months, overloading of the electrical transmission system, 

and the supply of natural gas necessary to reliably operate the NGCCs (impacts the electrical 

grid reliability and energy cost). Commenters stated that the most likely outcome is that the 

state's utilities will be left with the difficult decision of whether to jeopardize electric reliability 

in Arizona or risk noncompliance with the proposed carbon emission rate reduction goals.

Commenters argued the proposed rule is inequitable in its distribution of emission reduction 

targets, and the goal is not achievable for Arizona. Commenters stated there are serious flaws in 

the calculations and assumptions made for the State of Arizona. Commenters added the proposal 

is particularly egregious in its inequitable distribution of emission reduction targets. Commenters

stated the target for Arizona is 52 percent by 2030, which is the second most stringent target in 

the nation. Commenters stated further, the interim goal will require 90 percent of that reduction 

target to be met by 2020. Commenters stated these goals are simply not achievable, particularly 

given the limited resources available to the rural cooperatives in my district. Commenters

encouraged EPA to carefully review the comment letters written by the state utilities. 

Commenters concluded they will highlight the infrastructure limitations, and the imprudence of 

relying almost exclusively on one energy source.

Commenters stated Arizona's compliance goals illustrate the logical shortcomings in EPA's 

formulation of compliance targets for states. Commenters said Arizona has one of the youngest 

coal fleets in the United States, currently, the sixth youngest out of all the states; the blanket 

assumption that Arizona could attain the same degree of heat rate improvement as the older, less 

efficient plants in other states is clearly untenable. Commenters said Arizona has the largest and 

one of the newest and most efficient nuclear generating facilities in the United States; EPA's 

failure to consider the particulars of Arizona's nuclear fleet improperly overlooks the significance 

of this measure as an attainable means for compliance. Commenters said EPA made no 

evaluation about how the natural gas facilities in Arizona are used to meet existing loads or the 
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seasonal nature of Arizona's loads; EPA failed to consider whether there is access to sufficient 

gas transportation to operate all facilities to the degree EPA modeled for purposes of establishing 

the compliance targets, or whether Arizona utilities even have the legal right to use the power 

generated by all of the facilities considered. Commenters said Arizona already has one of the 

lowest per capita rates of carbon emission; Arizona also has a quickly growing population. 

Commenters said by contrast, many states with less stringent goals have older coal generation, 

declining populations and consequently higher per capita generation of carbon emissions. 

Commenters said plainly, Arizona is contributing significantly less GHG emissions than many 

other states; under such circumstances, placing more burdensome compliance targets on Arizona 

is illogical, unreasonable, arbitrary and capricious.

Commenters asked why did the EPA impose such an aggressive interim goal on Arizona; has the 

agency considered alternative approaches that would be less burdensome on the economy and 

the electric system in Arizona and other states.

Commenters asked will the EPA adjust the rule to avoid the localized impacts on Arizona's 

communities, particularly in rural Arizona.

Commenters stated an analysis of Arizona's compliance implications finds that the rule is neither 

flexible nor achievable and that implementation of this plan without modifications would result 

in severe impacts to the reliability of electric supply in the state and excessive cost implications 

for Arizona customers. Commenters said the CPP is projected to increase fuel and purchased 

power costs by 40% and generation capital expenditures by 30% when compared to more 

reasonable alternatives; major conclusions are: 

• The interim targets resulting from EPA's building blocks are unreasonable, are 

inequitable for Arizona, and cannot be achieved without major reliability 

concerns. 

• The infrastructure needs and costs associated with implementing the Clean Power 

Plan as it currently stands are very significant over a relatively brief period of 

time. 

• Alternative interim and final goals that fully consider the remaining useful life of 

existing plants would achieve significant carbon reductions without jeopardizing 

grid reliability and result in a lower cost to ratepayers. 

Commenters stated, it is not clear that even switching to NGCC will help AEPCO and similarly 

situated cooperatives and small utilities to meet the goal. Commenters said, EPA's goal of 702 

pounds per megawatt hour for Arizona is well below the carbon intensity that AEPCO can 

achieve at its units due to their elevation and design even with efficiency improvements. 

Commenters said, it is also not clear that AEPCO can purchase any existing units that could 

achieve this rate. Commenters said, AEPCO is thus forced to rely on energy efficiency and 

renewable energy. Commenters said, unfortunately, under Arizona utility structure AEPCO does 

not participate directly in those programs, its members do. Commenters said, under EPA's 

proposal it is not clear whether AEPCO can get credit for that work. Commenters concluded, 

EPA should reevaluate the building block assumptions using the target reductions for Arizona.
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Comment 22: AZ - Unequal and disproportionate burden on Arizona

Response 22: In this final CPP, the EPA has switched to a regional treatment of building blocks 

which results in a different state goal for Arizona. See section VII of the final rule preamble of 

the CPP for the EPA’s response to this comment and the CO2 Emission Performance Rate and 

Goal Computation TSD for CPP Final Rule supporting the final CPP.

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

Commenters stated that EPA's Approach Places an unequal and disproportionate burden on 

Arizona.

Commenters made the point that Arizona must achieve disproportionately larger emission 

reduction goals than a vast majority of other states across the country and a much larger 

reductions than all the states neighboring Arizona mostly because the Proposed Rule assumes 

Arizona has a relatively large amount of underutilized existing NGCC capacity. Commenters

stated that based on that assumption, EPA suggests that Arizona should simply displace all coalfired generation irrespective of technical limitations and economic dispatch concerns. 

Commenters stated that in contrast, if a state had not already made efforts to diversify its 

generation portfolio to take advantage of zero or lower carbon-emitting generation sources such 

as renewable and NGCC, then that state's reduction requirement to lower the nation's carbon 

footprint would be inexplicably small. Commenters concluded that EPA's approach to setting the 

states' carbon emission rate goals penalizes Arizona for a progressive, diverse generation mix.

Commenters stated that the proposed emissions reduction of 52% by 2030 is the second most 

stringent in the country and considerably higher than the other states in the southwestern region. 

Commenters added that this preposterous target will require the state to meet approximately 90% 

of the goal by 2020. Commenters concluded that with these standards, the EPA effectively 

ignores Arizona's careful planning and resource stewardship over the past several decades and 

imposes greater restrictions and higher costs on our residents than in other states with far higher 

carbon emissions.

Commenters stated that while Arizona only accounts for approximately 1.88 percent of the total 

CO2 emissions from generation units affected by the proposed rule, it is required to provide 

approximately 5.16 percent of the reduction by 2029. 

Commenters stated that Arizona falls in the middle of the states with respect to its carbon 

emissions. Commenters stated that Arizona's ratio of percent of reduction to percent of 

contribution is 2.74, the highest of any state. Commenters concluded that in Arizona's case, the 

proposed rule would require a 52 percent reduction in the emission rate from 2012 to 2029; this 

is the second largest reduction of all the states.

Commenters argued Arizona's treatment under the proposed rule is inequitable when compared 

to the rest of the nation.
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Commenters stated EPA's proposed final goal for Arizona would require a 52% reduction in 

CO2 emissions intensity from the proposed program baseline year of 2012; only one state, 

Washington, is being asked to do more. Commenters added interestingly, Arizona and 

Washington are similar in that both states currently have a large percentage of carbon-free 

generation. Commenters stated yet it appears that both states, as well as others that have already 

made significant investment in carbon-free resources, are penalized under EPA's proposal by 

being asked to do more than neighboring states with minimal carbon-free generation.

Commenters added Arizona's emissions reduction requirement is significantly more stringent 

than the requirements for neighboring states; when compared to Utah, for example, Arizona's 

goal is nearly two times as stringent.

Commenters stated the Proposed Rule raises several important issues for Arizona; first, the 

Proposed Rule would impose on Arizona greater reductions than required of most other states 

and does so more quickly. Commenters said the Proposed Rule would require a greater than 50 

percent reduction below 2012 levels (1453 lbs/MWH to 702 lbs/MWH). Commenters said the 

technical support documents indicate that this would result in incremental costs in Arizona that 

are greater than all but six states, even though Arizona already has very high levels of renewable 

non-emitting nuclear and hydro generation, resulting in a very low carbon intensity for our 

electric system.

Commenters stated as currently drafted, the Proposed Rule places an inequitable burden on 

Arizona to reduce its CO2 emissions by imposing overly stringent interim and final emission rate 

goals that impact system reliability and impose an unreasonable financial burden on Arizona 

customers.

Commenters stated implications for Arizona to comply with the proposed rule are 

disproportionately higher than nearly any other state. Commenters said Arizona has one of the 

most severe reduction targets of all states covered under the Clean Power Plan, with a reduction 

below its 2012 baseline of 52%, while most states' requirements are well below 50% with some 

less than 20%. Commenters said other states like Washington and South Carolina also have a 

large percentage reduction, although the drivers are different. Commenters said Washington 

State has only a small amount of coal, so relatively minor generation switching measures can 

achieve compliance. Commenters said South Carolina is impacted not by building block 2, as it 

has limited existing NGCC capacity, but rather by building block 3, due to the proposed new 

nuclear generation capacity in the state. Commenters said Arizona stands out as the state most 

impacted by building block 2, due to its high coal generation and significant existing NGCC 

capacity.

Comment 23: AZ - The Proposed Carbon Rule Does Not Recognize The Significant Efforts 

Already Made And Being Made In Arizona To Reduce CO2 Emissions

Response 23: In this final CPP, the EPA has switched to a regional treatment of building blocks 

which results in a different state goal for Arizona. See sections VI.D., VIII.B, and VIII.C. of the 

final rule preamble of the CPP for the EPA’s response to this comment. The actions listed in the 
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comment that occur after 2012 will help the state move towards compliance with its BSER 

reduction requirements.

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

Commenters stated Arizona utilities are already achieving significant reductions to their coal 

portfolios and the state's carbon emission rate as evidenced through the ACC's IRP process; an 

EPA enforcement overlay in areas not traditionally subject to EPA's regulatory oversight is not 

necessary or appropriate including: solar energy, requirements for regulated utilities to produce 

at least 15 percent of their retail sales from renewable resources by 2025; electric energy 

efficiency and demand-side management ("DSM") programs and measures; plans to retire, 

convert to natural gas, or reduce ownership in coal-fired power plants: 

• Arizona Public Service Company ("APS"): Retiring Cholla Units 1, 2 and 3 (647 

megawatts) 

• Tucson Electric Power Company ("TEP"): Reducing ownership in Springerville 1 

by 197 megawatts; Reducing ownership in San Juan by 170 megawatts; 

Converting Sundt Unit 4 from coal to natural gas (125 megawatts) 

• Arizona Electric Power Cooperative, Inc. ("AEPCO"); Converting Apache ST2 

from coal to natural gas (175 megawatts) 

Commenters stated while appreciative that the EPA's desire for uniformity in its proposal to 

reduce CO2 emissions from affected EGUs under Clean Air Act Section111 (d), this one-sizefits-all approach employs a flawed methodology, seeded with false assumptions, that has resulted 

in a fundamental misrepresentation of Arizona's electricity supply and delivery system. 

Commenters said Arizona utilities have developed an alternative approach that achieves a 

meaningful CO2 emission rate reduction for Arizona in an affordable manner. Commenters said 

this same approach could be applied consistently across the nation without significantly affecting 

the EPA's stated CO2 emission reductions while simultaneously rectifying the unique inequities 

that would occur in Arizona under the Proposal. Commenters strongly encouraged the EPA to 

incorporate this balanced approach in its final rule.

Comment 24: AZ - goal revisions

Response 24: For the EPA’s response to this comment, see sections V, VI, and VII of the final 

preamble and the CO2 Emission Performance Rate and Goal Computation TSD for CPP Final 

Rule supporting the final CPP.

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

Commenters stated that if EPA retains its building block methodology, EPA must revise 

Arizona's final goal so that it is based upon realistic and accurate assumptions. Commenters

offered changes in how Arizona's final goal should be recalculated. 
64

Commenters recommended the following changes: Use the maximum 2012 monthly capacity 

factor of 49.4 percent for Arizona as the base when re-dispatching NGCC generation up to 70 

percent capacity factor; use the average seasonal rating of 9,626 MW for Arizona NGCC units 

when re-dispatching to displace coal; use the 1031 lbs. CO2/Net MWh for NGCC units as 

allowed in section 111(b) for new NGCC units; allow coal units to operate through their 

remaining useful lives and book lives assuming a book life of 40 years, and allow for an 

additional 20 year life for older plants where major costs have been incurred for EPA required 

upgrades or retrofits. (Apache ST3, Coronado 1 & 2, Springerville 3 & 4 in service burning coal 

to beyond 2030); remove the at-risk nuclear component of Building Block 3; reduce the Building 

Block 1 efficiency improvement to 1 percent; include states without RE requirements and 

Arizona at 7 percent in determining the regional 2020 average RE goal of 16.00 percent for the 

Western Region; and Reduce the EE goal to 0.6 percent per year for states that had EE goals in 

place in 2012.

Commenters stated that all of the modifications proposed by the ACC to EPA's goal calculation 

methodology could easily be applied to all similarly situated states. Commenters stated that for 

Arizona, these changes will result in the cumulative effects on the AZ 2030 lbs CO2/MWh goal 

and cumulative percent reduction as follows: 

• EPA Goal Calculation: 702, 52%

• Use Maximum Monthly Capacity Factor: 794, 45% 

• All Prior Changes plus use of Seasonal Ratings: 846, 42%

• All Prior Changes plus use 1,031 lbs. CO2/Net MWh emissions for NGCC units: 

932, 36% 

• All Prior Changes plus allow coal units to operate through their remaining useful 

life and book life: 982, 32% 

• All Prior Changes plus remove at risk Nuclear component from Building Block 3: 

1,009, 31% 

• All Prior Changes plus reduce efficiency improvements in Building Block 1 to 

1%: 1,028, 29% 

• All Prior Changes plus include states with no RE goal in the calculation of the 

regional average RE goal and adjust Arizona RE goal to 7%: 1,042, 28% 

• All Prior Changes plus reduce EE goal to 0.6% per year for states with EE 

programs in place in 2012: 1,136, 22%

Commenters provided updated combined spreadsheets from the three EPA workbooks used to 

calculate the state 111(d) goals in order to allow the Arizona Department of Environmental 

Quality (ADEQ) to model the effects of various assumptions on the interim (2020-2029) and 

final (2029) lbs CO2/MWh rates for affected EGUs in Arizona.
65

Commenters included the following scenarios:

Commenters 1 scenario: EPA's goal calculation. Commenters stated that EPA's version has been 

modified to add columns showing the baseline rate, alternative baseline rate and total 2029 EE 

savings in MWh and to link to the RE and EE calculations in the other spreadsheets, rather than 

just incorporating the RE and EE values.

Commenters 2 scenario: Commenters stated that a rate calculation that assumes (a) 15 % RE by 

2029, (b) incremental EE savings of 1.61 % per year (the 2012 savings for Arizona according to 

EPA) after June 2014 and (c) adjusting redispatch to comply with the final goal of 702 lbs 

CO2/MWh. Commenters stated that consistent with the proposal, existing RE is counted in the 

calculation, but EE savings count only if they result from actions taken after the date of proposal. 

Commenters stated that this rate calculation also modifies the formula for determining NGCC 

redispatch by setting the post-redispatch generation equal to 2012 capacity (column J) x postredispatch CF (column U) x 8784. Commenters stated that this modification allows the use of 

Goal Seek to set redispatch generation to the levels that will achieve a particular final or interim 

rate-based goal (columns BD and BE).

Commenters 3 scenario: Same as 2, except 21 % RE by 2029 is assumed. 

Commenters 4 scenario: Same as 3, except 33% RE by 2029 and incremental EE savings of 2 % 

per year are assumed. 

Commenters 5 scenario: Same as 4, except redispatch is adjusted to achieve the interim goal of 

735 lbs CO2/MWh, rather than the final goal of 702. 

Commenters stated that for each scenario, they show the level of coal generation in 2020 that 

would be consistent with the other assumptions. 

Commenters stated that the RE spreadsheet (blue tab) includes EPA's original calculation for 

Arizona plus the alternative calculations used in the scenarios. Commenters stated that each EE 

alternative has its own spreadsheet (green tabs). Commenters stated that the RefTables 

spreadsheet provides some of the values needed by the EE calculations. 

Commenters also stated that these scenarios have been modeled solely for illustrative purposes 

only and do not reflect that any of the scenarios represents a cost-effective or feasible approach 

to compliance.

Comment 25: AZ - The EPA outreach to AZ Stakeholders

Response 25: See section II.I. 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:
66

Commenters stated the rule is complex and will have profound impacts on Arizona; and 

requested outreach to Arizona stakeholders.

Commenters stated that almost one year in the making, the administration's proposal is extremely 

complex and will have profound impacts on every sector of Arizona's economy, from our 

utilities to our families and businesses. Commenters concluded that outreach to Arizona 

stakeholders on a rule of this magnitude is imperative.

Commenters argued that CPP would be disastrous, and requested that AEPCO executives meet 

directly with EPA before rule is finalized.

Commenters stated that as written, the current proposal will have a significant impact on the state 

of Arizona's rural electric cooperatives, including Arizona Electric Power Cooperative, Inc. 

(AEPCO). Commenters urged EPA to work with AEPCO to mitigate these impacts before the 

rule is finalized.

Commenters stated that under the EPA's proposed plan, Arizona was given a carbon reduction 

goal of almost 52 percent, one of the highest carbon reduction goals of all 50 states. Commenters

noted that it is imperative that the EPA does not take a one-size-fits all approach and that rules 

with such far-reaching implications take into account the unique needs of rural communities. 

Commenters noted that as currently drafted, the EPA's proposed plan would be disastrous to 

AEPCO, its Member cooperatives, and the hundreds of thousands of members they serve.

Commenters stated that AEPCO has worked in good faith with the federal government in the 

past and already has committed to spending millions of dollars to meet environmental standards, 

most notably the EPA's recent regional haze requirements. Commenters added that given its 

history of compliance and its service to southern Arizona, AEPCO executives should have the 

opportunity to meet directly with EPA to discuss a potential solution that benefits our 

environment, saves jobs and allows for critical utility services to continue in rural Arizona.

Comment 26: The EPA should exempt AZ from the CPP until compliance status for the Navajo 

Generating Station is known/incorporated

Response 26: See sections IV.D, VII,. and VIII. of the final rule preamble of the CPP for the 

EPA’s response to this comment. EPA is finalizing source category rates and state goals for all 

affected EGUs in the contintenal U.S. including those on tribal lands. 

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

Commenters requested, due to unresolved ownership of the Navajo Generating Station (NGS) 

power plant (and subsequent uncertainty of compliance scenario requirements), that EPA 

withdraw or delay issuing a final rule. Commenters also requested a third party study of the 

issues surrounding ownership changes at the NGS, and/or exempt Arizona from complying with 

the final rule until the compliance scenario for NGS is known and can be incorporated into AZ's 

approach for compliance with the final rule.
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Commenters stated that the EPA issued a final ride effective October 7, 2014 requiring the 

Navajo Generating Station (NGS) power plant to reduce its nitrogen oxide emissions between 

2009 and 2044. Commenters stated that the final, rule outlines four possible emissions reduction 

compliance scenarios based on the ownership of the NOS on December 31, 2019. Commenters

stated that currently the three 750 megawatt coal-fired generating units that comprise the NOS 

are co-owned by six separate entities; the U.S. Bureau of Reclamation (24,3 percent), Salt River 

Project (21.7 percent), Los Angeles Department of Water and Power (21.2 percent), Arizona 

Public Service (14 percent), NV Energy (11.3 percent) and 'Noon Electric Power (73 percent).

Commenters stated that under the final rule, the applicable emissions reduction scenario that is 

enforced will depend on the outcome of ownership changes to the NGS, as well as whether NGS 

can increase its generation capacity (by no more than 189 megawatts). Commenters explained 

that if the Navajo Nation does not purchase an ownership share in the NGS by December 31, 

2019 then the most stringent emissions reduction requirements are triggered, including 

permanently closing unit 1 by 12/31/19. Commenters stated that if the Navajo Nation is able to 

purchase an ownership share prior to the trigger date then less stringent emission reductions 

targets are required and coal-fired generation may continue, however, generation capacity would 

have to be reduced and nitrogen oxide limits would take effect by 2010. 

Commenters stated that it is the opinion of the Authority that the unresolved ownership situation 

surrounding the NGS, and therefore uncertainly as to which compliance scenario will be 

required, will have a material impact on the State of Arizona's ability to comply with 

requirements under the proposed rule.

Comment 27: AZ - forced coal retirements

Response 27: See section 5.11 of the RTC of a discussion on stranded assets as well as the 

Stranded Assets Analayis MEMO from July 2015 in the Docket for this rulemaking.

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

Commenters asked did EPA analyze the impact of stranded costs from early retirement of coalfired power plants on Arizona's electric rates, if so, please explain the process and results.

Commenters stated under the literal application of the Clean Power Plan building blocks, 

Arizona would be required to retire all of its existing coal-fired generation in 2020 to comply 

with EPA's goals (except for tribal coal). Commenters said the total elimination of coal-fired 

generation in Arizona required to meet the CPP interim targets would require an estimated 10 

GW of new resource capacity from 2020 to 2030 to meet future reserve margins for Arizona's 

peak summer season, with about 2.3GW directly attributed to CPP impacts and not load growth. 

Commenters said the only coal-fired generation included beyond 2020 is sourced from the 

Navajo Generation Station that is on tribal land and not subject to Arizona interim and final 

goals.
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Comment 28: AZ - BB2 Re-dispatch issues

Response 28: See section V.D. of the final rule preamble of the CPP for the EPA’s response to 

this comment and more information about Building Block 2.

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

Commenters suggested that in applying Building Block 2, the EPA should take into account that 

a significant amount of the merchant owned generation located in Arizona is delivered out of

state. Commenters indicated that this represents approximately 50 percent of the NGCC capacity 

in 2012 that the EPA assumed would be available for use by Arizona utilities to serve load 

within the state. Commenters said the EPA should take into account that a significant amount of 

electricity generated in Arizona is exported.

Commenters stated agreement that strict application of Building Block 2 to Arizona by 2020 

would not constitute BSER for four reasons: Commenters said, first, requiring the retirement of 

Arizona's entire coal fleet by 2020, which would be the effect of imposing BB2 as a stand-alone 

requirement, would impose unreasonable costs in the form of stranded investments. Commenters 

stated, second, the EPA modeling of the cost impacts of redispatch pursuant to BB2 appears to 

be flawed. Commenters said, third, the assumption of a 2020 implementation date for BB2 fails 

to adequately account for the need to develop the infrastructure required for redispatch. 

Commenters stated, finally, full imposition of BB2 by 2020 or even 2030 could jeopardize the 

reliability of Arizona's grid and would be inconsistent with the EPA's obligation to consider 

"energy requirements." 

Commenters stated due to the large amount of NGCC capacity in Arizona, this building block 

has a significant impact on its state goal computation and would require significant and sudden 

shifts in the state's generation mix to meet the resulting emission rate reductions. Commenters in 

fact, as applied in the EPA's building block approach, the increased use of NGCC units in the 

state would displace all coal fired generation in the state, in effect forcing the retirement of all of 

the approximately 3,316 MW of coal capacity operating as of the 2012 baseline net already 

planned retirements and units slated for conversion to natural gas.

Commenters stated that the re-dispatch to 100% NGCC is untenable and unacceptable.

Commenters stated that according to calculations, meeting this target would require a 100% 

retirement of coal generation in Arizona and a 100% increase in reliance on natural gas 

generation, all by 2020. Commenters noted that Arizona's Co-ops' generation portfolios currently 

include 80% coal, 5% natural gas and less than 1% in renewables. Commenters noted that 

indeed, the EPA's Proposed Rule would require that a titanic shift in these portfolios take place 

in a very short period of time without taking into account the transmission and generation 

constraints, voltage regulation limitations, and various other factors that comprise a very 

complex system. Commenters added that rural communities will suffer significant economic 

consequences from the imposition of this Proposed Rule that include job losses at coal plants, 

increased energy costs, reduced economic development opportunities, and higher costs for basic 

consumer goods. 
69

Commenters added that further, the coal-fired Apache Generating Station, which is owned by 

Co-ops in Arizona, was built under the Fuel Use Act of 1978 as the only viable alternative 

energy source at the time. Commenters stated that now, the same federal government that 

mandated its construction is now ridiculously requiring its closure. Commenters added that this 

is particularly disconcerting as evidence mounts that the original notions of "global warming" 

and then "climate change" impact scenarios are no longer supported by numerous climatological 

models.

Commenters stated Arizona operates outside of an RTO or ISO; thus, does not have the same 

flexibility to easily redispatch as other states. Commenters said this scale of this redispatch 

mixed with the interim goal creates a perfect storm that could expose rate pairs to serious 

reliability and safety issues. Commenters said in a dessert Southwest summer reliable electricity 

is not a luxury, it is a life sustaining necessity. Commenters urged the EPA to provide a 

substantially longer runway for states to make this coal to natural gas transition and include a 

phase-in approach to redispatch.

Commenters stated contrary to the EPA's stated objective of "maintaining an affordable, reliable, 

and diverse energy mix" [79 FR 34832], the Proposal would result in Arizona losing the 

diversification of resources it has developed over the past several decades. Commenters said in 

terms of resource diversification and an "all of the above" energy strategy, Arizona is a model 

state. Commenters said the EPA's Proposal would erode that benefit by concentrating Arizona's 

resource portfolio on natural gas. Commenters said given the historical swings in natural gas 

prices and availability, coupled with the absence of natural gas storage in Arizona, that is risky 

proposition; it should not be the mandate under the Proposal. Commenters said over the last 70 

years, Arizona has developed a balanced and diversified system to deliver safe, reliable, and 

affordable energy. Commenters said the state's utilities already are transitioning to a less carbonintensive system of providing energy; however, the EPA is requiring the state to fundamentally 

reshape its system in five years. Commenters said such a drastic shift will have serious reliability 

and cost implications for Arizona residents. 

Commenters stated the Proposed Rule's assumed implementation of the entirety of Building 

Block 2 (BB2) in 2020 deprives Arizona, of any meaningful flexibility in implementing the CPP; 

any change in the proposed balance between BBs 1, 2, 3 or 4 results in Arizona being unable to 

achieve the Interim Goal, or else results in Arizona greatly overshooting the Final Goal.

Commenters said as a result, Arizona is basically locked into EPA's goal setting exercise, which 

requires the complete redispatch of Arizona's coal-fired EGUs to NGCC EGUs in 2020. 

Comment 29: AZ - BB3 RE

Response 29: See section V.E. of the final rule preamble of the CPP for the EPA’s response to 

this comment and more information about Building Block 3.

The following are summaries of the specific public comments under this comment:
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Commenters said that the EPA should adjust Arizona's 10% RE goal down to 7% to account for 

distributed generation, and indicated that similar adjustments may be needed for other states as 

well. 

Commenters said that Building Block 3 requires substitution of higher CO2 emitting fossil fuel 

generation with zero emitting RE generation, and the EPA developed a "best practices" scenario 

for RE generation. Commenters said the best practices scenario for each state consists of an 

annual RE growth factor applied to the state's historical RE generation, subject to a maximum 

RE generation target, and the growth factors and targets were developed separately for each of 

the six regions.

Commenters said the EPA used 2012 as the base year for each of the states in the region and 

summed up the amounts for all states in the region to determine a regional starting level. 

Commenters said the EPA's approach was to calculate a goal amount of RE for 2029 based upon 

the average of the 2020 RE standards for each state, excluding from the average states with no 

state mandated RPS goal, and then calculating the annual growth rate required to reach the 2029 

goal from the region's actual 2012 utility scale RE energy. Commenters said the EPA then 

applied the annual growth rate on a state by state basis to each state's 2012 actual RE energy 

beginning in 2017 to determine that state's yearly total RE MWh from 2017 through 2029, and 

each state's RE MWh was limited to its 2020 RPS goal. Commenters said that in Arizona, the 

total RE energy could not exceed 10 percent.

Commenters said that with respect to the goal of 10 percent in 2020, which was used for Arizona 

in calculating the average goal for the Western region, the EPA's assumptions contained an 

error. Commenters said that in the ACC's rules, of the 10 percent goal for 2020, 30 percent must 

come from distributed generation, which the EPA has not included in its goal calculations. 

Commenters said that the EPA should adjust the goal used for Arizona down to 7 percent to 

account for these exclusions, and indicated that similar adjustments for other states may need to 

be made.

Commenters said that one of the assumptions the EPA used in calculating Arizona's total RE 

energy limit was incorrect.

Commenters said that Building Block 3 requires substitution of higher CO2 emitting fossil fuel 

generation with zero emitting RE generation, and the EPA developed a "best practices" scenario 

for RE generation. Commenters said the best practices scenario for each state consists of an 

annual RE growth factor applied to the states historical RE generation, subject to a maximum RE 

generation target, and the growth factors and targets were developed separately for each of the 

six regions.

Commenters said the EPA used 2012 as the base year for each of the states in the region and 

summed up the amounts for all states in the region to determine a regional starting level. 

Commenters said the EPA's approach was to calculate a goal amount of RE for 2029 based upon 

the average of the 2020 RE standards for each state, excluding from the average states with no 

state mandated RPS goal, and then calculating the annual growth rate required to reach the 2029 

goal from the region's actual 2012 utility scale RE energy. Commenters said the EPA then 

applied the annual growth rate on a state by state basis to each state's 2012 actual RE energy 
71

beginning in 2017 to determine that state's yearly total RE MWh from 2017 through 2029, and 

each state's RE MWh was limited to its 2020 RPS goal. Commenters said that in Arizona, the 

total RE energy could not exceed 10 percent.

Commenters said that with respect to the goal of 10 percent in 2020, which was used for Arizona 

in calculating the average goal for the Western region, the EPA's assumptions contained an error. 

Commenters said that this goal, taken from the Arizona Corporation Commission's (ACC's) 

Renewable Energy Standard Tariff ("REST") rules, does not apply to all load in Arizona. 

Commenters said that the REST rules are only applicable to utilities under the jurisdiction of the 

ACC, and this only accounts for about 60 percent of the load in Arizona.

Commenters stated EPA's proposed emissions reduction target for Arizona underestimates the 

emissions reductions the State can and indeed, under state law, must achieve under Building 

Block 3 related to renewable energy. Commenters said under Arizona's Renewable Energy 

Standard and Tariff (REST), five percent of the electricity generated from the State's regulated 

utilities must come from qualifying renewables in 2015, ten percent in 2020 and fifteen percent 

by 2025. Commenters said this mandated increase in renewables generation will displace 

substantial amounts of fossil fuel generation; this State-mandated increase of renewable 

generation exceeds that assumed by EPA when EPA established the State's target emissions 

reduction amount. Commenters said under EPA assumptions, by 2029, 4 percent of Arizona's 

annual electricity generation should come from renewables, an increase of just 2 percent from 

2012 amounts. Commenters said thus whereas, under EPA assumptions, increases in renewables 

generation accounts for just 10 percent of the emissions reductions needed for Arizona to meet 

its 2029 target, under Arizona's mandatory REST renewables generation can in fact account for 

19 percent of the emissions reductions that will be required. Commenters added given the current 

relatively low cost of utility-scale solar photovoltaic (PV) capacity and continued likely PV cost 

reductions, the share of generation from renewables in Arizona by 2025 could well exceed the 

RPS target, with a correspondingly greater contribution to emissions reductions.

Commenters stated with respect to the state authority that EPA would rely upon for purposes of 

establishing compliance targets, EPA did not account for the fact that in Arizona's case, the 

REST as well as the EE Rules both have finite durations and actually terminate coincident with 

the interim compliance target set in the proposed rule; it would be exceedingly premature for 

EPA to presume that Arizona will perpetuate, much less surpass the standards set for 2020 by 

Arizona's rules for purposes of setting either an interim compliance target or a final target. 

Commenters stated with regard to RE, Arizona has experienced numerous challenges that may 

impact the ongoing development of renewable generation in the state. Commenters said EPA's 

assumption in Arizona's case that the future of renewable generation is invariably aimed toward 

unfettered expansion is, therefore, entirely unsupportable and is contradicted by the emerging 

regulatory challenges that have already been experienced; the Proposed Carbon Rule sets 

compliance targets on faulty bases and should be revised to account for these issues. 

Commenters stated, the state of Arizona provides a good example of the disconnect between 

state policy and achievable renewable energy generation. Commenters said, with high solar and 

geothermal potential and an active renewable energy industry, Arizona has among the most 

attractive markets for renewable energy generation. Commenters said, however, the state has a 
72

relatively modest RPS while the West region has the least ambitious renewable energy growth 

factor under the Proposed Rule. Commenters said, as a result, the EPA target estimates that 

Arizona would generate 3,663 GWh of renewable energy by 2030, constituting just 4 percent of 

its 2012 generation. Commenters concluded, this puts Arizona's target for renewable energy 

generation in the bottom quarter of Building Block 3 targets. 

Comment 30: AZ - BB4 EE

Response 30: The EPA is not including demand-side energy efficiency (building block four) in 

the final BSER determination. See section V.A. of the final rule preamble of the CPP for the 

EPA’s response to this comment and more information about Building Block 4.

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

Commenters stated under Arizona's energy efficiency standard, the State's investor-owned 

utilities, electric cooperatives and the Salt River Project, must ramp up the efficiency of their 

electricity production by percentages that exceed the assumptions underlying EPA's target for the 

State; specifically, under state law, Arizona utilities and cooperatives must conserve between 

15.75 (Salt River Project) and 22 (investor-owned utilities) percent of electricity sales by 2020. 

Commenters said under EPA's more lenient assumptions for demand-side energy efficiency

(Block 4), the State's utilities need only increase efficiency by 1.5 percent per year after 2017 and 

need only reach a maximum of 5.2 percent in 2020 and 11.4 percent in 2029; thus there is an 

over 10 percent point difference between the State's and EPA's assumptions regarding energy 

efficiency in just 2020. Commenters said Arizona's ability and, indeed, obligation to 

"overcomply" with the proposed federal targets for energy efficiency will ease the costs and 

feasibility of the State's efforts to comply with its overall Clean Power Plan carbon emissions 

reduction target. Commenters said EPA's flexibility in allowing states to achieve reductions 

through "beyond the fenceline" measures by utilizing policies that are currently in place such as 

renewable energy standards and energy efficiency standards is crucial to Arizona's ability to 

comply with federal targets in a cost-effective manner. 

Comment 31: AZ - In setting goals, the EPA should assume that any units with remaining life 

extending beyond 2030 continue to operate

Response 31: For the EPA’s response to this comment, see the CO2 Emission Performance Rate 

and Goal Computation TSD for CPP Final Rule supporting the final CPP.

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

Commenters said that in setting state goals, the EPA should assume any coal units whose 

remaining useful life and book life extends beyond 2030 continue to operate.

Commenters said that in setting state goals, the EPA's should include any coal units whose 

remaining useful life and book life extends beyond 2030 as continuing to 
73

operating. Commenters added that this should also include coal units that have made recent 

major investments for prior EPA-mandated emissions reductions.

Comment 32: AZ - State-specific emission factors for BB2 are inconsistent with analysis 

conducted for new units

Response 32: See section V.D. of the final rule preamble of the CPP for the EPA’s response to 

this comment and more information about Building Block 2. EPA relies on the baseline 

emission rate from affected sources in its quantification of BSER. Assuming a higher emission 

rate than currently observed would be inconsistent with the best system of emission reductions. 

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

Commenters said that the state-specific emission factors used to calculate the NGCC component 

of the baseline and target goal rates is inconsistent with EPA's analysis conducted for new units 

under section 111(b).

Commenters said that the state-specific emission factors used to calculate the NGCC component 

of the baseline and goal rates is inconsistent with "EPA's analysis regarding emission rate 

capabilities for new, highly efficient units under section 111(b)." Commenters said that in all but 

three states, the EPA's method assumes that existing NGCCs will emit CO2

at a lower rate than the lowest standard (1,000 lbs CO2/MWh) for new NGCCs. 

Commenters calculated the impact of combining the stranded investment exclusion with an 

assumed NGCC rate no lower than 1,000 lbs CO2/MWh.

Comment 33: AZ - Impact of BB2 and interim goal on Arizona

Response 33: For the EPA’s response to this comment, see the CO2 Emission Performance Rate 

and Goal Computation TSD for CPP Final Rule supporting the final CPP. Although EPA 

disagrees with the assertion that its goal setting process at proposal would have required closure 

of all coal facilities in Arizona, it has taken a regional approach to quantifying BSER in this final 

rule that it believes further addresses Arizona central concern about the concentrated impact of 

incremental NGCC generation if focused purely on replacing in-state fossil steam generation.

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

Commenters said that because application of BB2 to Arizona results in assumed retirement of 

entire coal fleet by 2020, the effects on Arizona are acute, and the more that Arizona relies on 

BB3 and BB4 to achieve compliance with the final goal, the further it gets away from reaching 

the interim goal. 
74

Commenters said that since application of BB2 to Arizona results in the assumed retirement of 

the state's entire coal fleet by 2020 and accounts for 81 percent of the reduction in the state's 

adjusted baseline rate, the effect on this state is particularly acute.

Commenters stated the more Arizona relies on BB3 and BB4 to achieve compliance with the 

final goal of 702 lbs CO2/MWh, the farther it gets from compliance with the interim goal. 

Commenters said conversely, if Arizona designs its program to comply with the interim goal, it 

ends up with a final rate that is far lower than necessary to comply with the final standard and 

ends up preserving a much smaller portion of its existing coal-fired generation 

resources. Commenters said that based on a review of the EPA's data, many other states face this 

same issue, including Texas, Florida, Arkansas, North Carolina and Oklahoma.

Comment 34: AZ - Impact of CPP on ozone non-attainment area

Response 34: See section I.A. of the final rule preamble of the CPP for the EPA’s response to 

this comment. EPA BSER assumptions are not premised on any new NGCC build. 

Furthermore, EPA compliance modeling anticipates that there will be less new gas build relative 

to a base case scenario. See the Regulatory Impact Analysis. 

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

Commenters said increased NGCC generation will add to existing ozone non-attainment 

problems in Arizona.

Commenters said that most existing NGCC generation in Arizona is located in Maricopa County, 

in or near the 8-hour ozone nonattainment area. Commenters said that increased operation of 

NGCC units, and the corresponding increase in NOx emissions, will make attainment of the 

ozone NAAQS significantly more difficult, especially if, as anticipated, EPA reduces the 

standard to 70 ppb or lower next month.

Commenters said it is likely that to meet the state's goal, or even a substantially higher goal, 

Arizona utilities would need to construct new simple cycle natural gas or NGCC generation, 

which will be difficult, if not impossible, in or near ozone nonattainment areas. Commenters said 

that in particular, Tucson Electric Power (TEP) is substantially dependent on coal generation at 

the Springerville station to serve its customers and would probably have to construct simple 

cycle natural gas or NGCC near its Tucson customers to compensate for retirements at 

Springerville. Commenters said that Tucson has experienced 8-hour ozone concentrations in 

excess of 70 ppb and is therefore likely to be a nonattainment area after the ozone NAAQS is 

revised.

Comment 35: AZ - Targets are too strict and don't give credit for Palo Verde nuclear

Response 35: See section V.A. of the final rule preamble of the CPP for the EPA’s response to 

this comment. EPA has modified it approach to determining state goals. Final rule BSER is 
75

premised of a regionalized building block two. For stats with large NGCC inventories like 

Arizona, this reduces the amount of in-state impact of that incremental NGCC potential.

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

Commenters said that the target set for Arizona fails to recognize peaking requirements, fails to 

give credit for Palo Verde nuclear station, and requires states to inequitably share the burden of 

emissions reductions.

Commenters said the most concerning aspect of the proposal for Arizona is the target reduction. 

Commenters said that Arizona is asked to reduce carbon emissions by 52 percent, which is the 

second highest reduction in the nation. Commenters said this goal fails to recognize several 

realities, such as the need to maintain the current capacity of the system due to Arizona's unique 

energy demands during certain times of the year. Commenters indicated this percentage 

reduction also fails to give Arizona credit for the Palo Verde Generating Station, which is the 

largest nuclear generating facility in the United States and a zero carbon emission source. 

Commenters said the EPA's method of determining each state's reduction requirement should 

take all sources into consideration, and also provide a fair distribution of the impact of reductions 

between states rather than requiring citizens of one state to inequitably shoulder the burden.

Comment 36: AZ cannot shutter coal resources and replace with natural gas. Forced early 

retirements would devastate rural economies

Response 36: See response 35

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

Commenters argued Arizona's coal resources cannot be shuttered and replaced by excess natural 

gas generation capacity. Commenters also argued the closures would devastate rural economies.

Commenters stated closure of the coal generating stations in Arizona would devastate the 

economies of rural communities, where the plants support high-wage employment and provide a 

critical tax base for schools and local governments. Commenters stated rate increases resulting 

from the Proposed Rule would disproportionally affect rural consumers and exacerbate the 

growing problem of poverty in these areas. Commenters encouraged EPA to consider the 

impacts this Proposed Rule would have on Arizona's rural families and businesses.

Comment 37: AZ - The EPA wrongly assumes Arizona can transition the state's energy 

portfolio

Response 37: See section V.D. of the final rule preamble of the CPP for the EPA’s response to 

this comment and more information about Building Block 2. In the final rule, EPA has taken a 
76

regionalized approach to block two, adjusted the start of the interim period to 2022, and assumed 

a more gradual deployment of building block two. These changes address the concerns 

expressed in the comment below.

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

Commenters stated that the EPA wrongly assumes that Arizona's reliable and affordable coal 

resources can be easily shuttered and replaced by "excess" natural gas generation capacity. 

Commenters stated that this assumption, which is the foundation of the Proposed Rule's goals for 

Arizona, demonstrates the EPA's misunderstanding of the ownership of these resources, how 

Arizona uses these resources and coal resources to meet summer peak load demands, the current 

limitations of Arizona's natural gas infrastructure and storage, and the availability of 

transmission resources. Commenters added that Arizona's aggressive interim and final goals 

presume the state has an unfettered ability to perform a complex transition of the state's energy 

supply by 2020, including retiring most of the state's coal-fired generation units and making a 

significant investment in new infrastructure to replace that generation. Commenters stated that 

EPA's own modeling shows that this transition cannot happen, demonstrating that such a 

transition is not economically viable, not technically viable, or both. Commenters encouraged

EPA to reconsider this flawed assumption and correct the Proposed Rule to reflect the realities in 

Arizona.

Comment 38: AZ - list of questions for the EPA; considerations for Arizona

Response 38: See sections V.A., V.C., V.D., V.E., and VII of the final rule preamble of the CPP 

and the CO2 Emission Performance Rate and Goal Computation TSD for CPP Final Rule 

supporting the final CPP for the EPA’s response to this comment. EPA has revised its timing 

and approach to interim goals. At the proposal, Arizona’s interim goal was much closer to its 

final goal (reflecting less of a glidepath), than it is in this final CPP rule.

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

Commenters questioned the following:

Why did the EPA impose such an aggressive interim goal on Arizona? Has the agency 

considered alternative approaches that would be less burdensome on the economy and the

electric system in Arizona and other states? 

Will the EPA adjust the rule to avoid the localized impacts on Arizona's communities, 

particularly in rural Arizona? 

Did the EPA analyze the impacts of stranded costs to utilities? Did the EPA account for the 

remaining useful life of the current generation assets, including those with multiple decades of 

remaining useful life? 
77

Will the EPA provide its analysis of how it can direct the Arizona Corporation Commission to 

order merchant natural gas generators in Arizona to use these plants to serve instate load to offset 

the closure of coal facilities? 

Will the EPA explain why it did not provide credit for the state's zero-emission sources such as 

nuclear and hydroelectric generation, thus failing to recognize Arizona's large proportion of 

existing carbon-free resources in the goal-setting process?

Comment 39: AZ - NCGG generation capacity isn't available to meet peak demands

Response 39: See section V.D. of the final rule preamble of the CPP for the EPA’s response to 

this comment and more information about Building Block 2. In this final CPP, EPA has taken a 

different approach to block two. Moreover, the source category rates (and corresponding state 

goals) are premised off region-wide fossil steam replacement potential in the least stringent 

region (the eastern U.S.). The source category rates, even though not prescriptive, still embody a 

significant amount of fossil steam (coal steam generation) in their rate derivation. EPA does not 

believe that the final source category rates or state goals would require Arizona to operate its 

coal fleet in the manner described below. 

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

Commenters stated that NGCC generation capacity isn't available to meet peak demands.

Commenters described the process by which EPA concluded that NGCC can reliably achieve a 

70 percent capacity factor, and described flaws in the assumptions that EPA made in its redispatch analysis. 

Commenters stated that when determining the potential generation capacity of the NGCCs 

located within Arizona, EPA used the nameplate rating of the units; although, the nameplate 

rating of NGCC is not the same as the net available output from the units. Commenters explained 

that net available capacity output is influenced by a number of factors, such as site elevation, 

humidity, ambient temperatures, turbine rating, and plant loads. Commenters stated that in 

Arizona, peak electrical demand is typically proportional to peak ambient temperatures. 

Commenters stated that when electrical demand is at its highest is the same time when the units' 

net capacities are most limited due to ambient conditions. Commenters stated that because EPA 

did not take this into consideration, NGCC generation capacity assumed by EPA is 

approximately 2,000 MW higher than what is actually available during peak demand periods.

Commenters stated there are differences between the generation capacities of NGCC units 

located within Arizona assumed by EPA compared to the actual available capacities of these 

units. 

Commenters stated that EPA's second flawed assumption is the use of an annual capacity factor 

to determine the margin of additional energy output that can be generated by NGCC in Arizona. 

Commenters explained that in doing this, EPA must have assumed the annual capacity factor for 

NGCC in Arizona is a rather flat line, when in reality there is huge difference between the 
78

electrical demands in the summer months versus the remainder of the year. Commenters stated 

that for most years, the average summer demand is more than twice the average demand for the 

remainder of the year.

Commenters stated that in Arizona, the most critical period for utilization of generation capacity 

is the period from June through September. Commenters used data from EPA's Clean Air 

Markets Division to plot the historical output from all of NGCC units located in Arizona during 

August 2012 to show the actual NGCC capacity that is available during summer months versus 

how much the EPA assumes is available for re-dispatch. Commenters stated that during hour 16 

on August 7, 2012, Arizona NGCCs were generating 8,455 MW (net), and the coal and gas 

steam units were generating 4,098 MW (net). 

Commenters stated that in order to re-dispatch all coal and gas steam with NGCC generation as 

assumed by EPA, the NGCCs would have to be operating at 12,533 MW (8,455 MW + 4,098 

MW). Commenters said maximum capacity assuming all units were fully available, however, 

was only 9,305 MW, a difference of 3,248 MW. Commenters stated that only 850 MW of the 

4,098 MW of required capacity would have been available for re-dispatch in this hour, leaving 

3,248 MW of demand that would still need to be met. Commenters stated that this suggests that 

2,354 MW of coal would have been needed for reliability purposes. Commenters stated that in 

fact, there was not enough combined cycle capacity available for re-dispatch in the state of 

Arizona for thirty of the thirty-one days in August, 2012.

Commenters stated that almost 50 percent of the time during August 2012 the energy demand 

that would normally be provided by coal-fired generation exceeds the available capacity of all of 

the NGCC units in Arizona. Commenters concluded that therefore, it is not possible to redispatch all coal-fired generation to the existing NGCC fleet and meet Arizona's load demands 

with NGCC during peak demand periods.

Commenters stated that the same analysis was performed for all hours of 2012. Commenters

stated that for nearly 800 hours throughout the year, the NGCC units in Arizona could not meet 

the energy demand. 

Commenters stated that during this period, the average capacity factor for all the NGCC units in 

Arizona would have to increase from 64 percent to 98 percent, which far exceeds the 70 percent 

cap proposed by EPA. Commenters explained that because of the substantial increase in 

electrical demand in Arizona during peak demands, the annual average capacity factor of 70 

percent for the NGCC units cannot be used as a basis for determining the additional capacity the 

NGCC units can supply during peak demand periods.

Commenters added that NGCC units are complex mechanical systems that malfunction even 

under the best of readiness and preventive maintenance programs. Commenters stated that it is 

naive and unrealistic to assume there will not be forced outages due to mechanical issues with 

these units from time to time. Commenters stated that such outages will also reduce the 

availability of NGCC capacity, which is part of the reason why reserve margins are required.

Commenters stated that EPA suggested that the state's utilities could just operate coal-fired 

generation during peak demand periods, but this is not a viable option. Commenters stated that 
79

the coal-fired EGUs in Arizona are large, complex units. Commenters added that typically, such 

units are not designed and engineered to sit idle for extended periods of time; such practices 

would challenge reliable operation of the units. Commenters concluded that moreover, the 

staffing and maintenance necessary to support such a scenario would not be economically 

justified.

Comment 40: AZ - Re-dispatch will require construction of new NGCC units with an 

unreasonable timeframe

Response 40: See section V.D. of the final rule preamble of the CPP for the EPA’s response to 

this comment and more information about Building Block 2. EPA BSER quantification for 

proposal and final rule does not assume any new NGCC construction.

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

Commenters stated that re-dispatch will require construction of new NGCC units with an 

unrealistic timeframe. 

Commenters stated that in addition to the shortage of electrical capacity to meet Arizona needs 

during peak demand periods, there will also be a general shortage of electrical capacity if all of 

the state's coal-fired generation shuts down. Commenters commissioned PACE Global to 

conduct a study of the impact of the Proposed Rule in Arizona. Commenters stated that PACE 

Global used an AuroraXMP platform to model an hourly chronological dispatch model to 

simulate the economic dispatch of power within a competitive framework. Commenters stated 

that based on this modeling, PACE Global concluded that an additional 3.5 GW of new natural 

gas-fired capacity will be needed by 2020 to meet the load and reserve margins. Commenters

added that of this additional generation, 2.3 GW is directly attributable to the Proposed Rule.

Commenters stated that because utilities cannot be expected to prematurely make such an 

investment, the time frame for designing, engineering, permitting, and constructing this new 

NGCC capacity is only two to three years. Commenters added that it is unrealistic to believe that 

such a feat is possible. Commenters stated that in addition to mammoth amount of work that 

would be involved for the utilities, there is a huge concern regarding the ability of original 

equipment manufacturers to supply the necessary equipment and the availability of the labor 

necessary to construct the equipment in such a short time period.

Comment 41: AZ - radically compressed timeline, AZ has virtually no time for proper 

economic, safety, and reliability based preparation; pipelines; natural gas interruption and supply

Response 41: See section I.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:
80

Radically compressed timeline. Commenters stated that according to the proposed rule EPA 

assumes Arizona would be able to complete this foundational transition from coal to natural gas 

by around 2020 - About five years after states get clarity on targets, and even less time from 

when state plans actually gain approval.

Commenters added that since Arizona has no natural gas storage and only two major national gas 

pipelines, this radically compressed timeline leaves Arizona virtually no time for proper 

economic, safety, and reliability based preparation.

Commenters stated NERC-CAISO has determined that Arizona's "existing pipeline capacity is 

not adequate to handle incremental gas needs of the state under the CPP." (NERC-CAISO Joint 

Report, "Maintaining Bulk Power System Reliability while Integrating Variable Energy 

Resources"). Commenters said EPA has not given adequate consideration of this issue and it 

requires a change in the timing of BB2 and revision to the Interim Goal, at the very least.

Pipelines. Commenters stated Arizona benefits primarily, though not exclusively, from two longhaul pipelines, Transwestern and El Paso Natural Gas pipelines; both of these pipelines are 

expected to remain highly utilized, as they currently are, to serve demand in New Mexico, 

Arizona and California and also to serve rising exports to Mexico. Commenters said given the 

current high capacity factor of pipeline usage in this region, the addition of Clean Power Plan 

induced natural gas demand for power needs in the southwest leads to concerns that the current 

pipeline system is inadequate to serve all demand during periods of peak usage. Commenters

said Pace Global's pipeline flow model analysis indicates that under the Clean Power Plan, 

expansions would be needed to meet consumption needs and maintain reliability on both the 

northern and southern legs of the El Paso pipeline and on the Transwestern pipeline. 

Commenters said the Pace Global's pipeline flow model analysis indicates that under the Clean 

Power Plan, the following expansions would be needed to meet consumption needs and maintain 

reliability: 

El Paso Southern leg would require expansion by the early 2020s if not sooner, as it is expected 

to exceed design flow by 2022 based on average flows. 

El Paso Northern leg would require expansion by 2025. 

Transwestern pipeline, which is already over 95% utilized, would benefit from expansion, 

although most of the incremental flows will impact the El Paso pipeline system.

Commenters stated generators will need to secure existing pipeline capacity in order to ensure 

readily available supply; even so, generators who are in the money and could generate, but who 

rely on interruptible pipeline capacity, may find themselves unable to dispatch during periods of 

high demand due to pipeline constraints. Commenters said this significant increase in natural gas 

demand coupled with inadequate natural gas storage and transportation infrastructure will 

ultimately lead to higher natural gas and power price volatility in the Desert Southwest. 

Concerns about natural gas interruption and supply issues. Commenters stated that EPA also 

believes that since no particular NGCC unit is required to achieve a specific utilization rate, that 

other NGCC units located in the state could make up for the loss due to a natural gas supply 

issue. Commenters stated that this does not apply well in Arizona because the state utilities are 
81

limited to one primary gas supplier and, to a lesser extent, a secondary gas supplier. Commenters

added that furthermore, most all of the NGCC units within the state are located within a small 

geographic region. Commenters stated that accordingly, any natural gas supply interruption to 

any one particular NGCC is likely to also be an interruption to most other NGCCs within the 

state.

Commenters stated that EPA relies on the ability of transmission planners to overcome any 

impediment and be able to assure the natural gas supply is available to meet EPA's proposed redispatch plan. Commenters warned that while transmission planners typically are quite skillful, 

the nation's natural gas supply system is in a tremendous state of flux and surely will have to 

overcome challenges never before witnessed.

Commenters added that the PACE Global study identified that the incremental increase of 

natural gas demand resulting from the increased utilization of NGCC units and the need for new 

NGCC capacity to fill the void left from the retirement of coal-fired units will exceed the current 

natural gas supply capacity. Commenters stated that Arizona's natural gas needs for power 

generation alone would increase by an estimated 500 MMcf/d, representing more than a 55 

percent increase relative to Arizona's current power sector natural gas consumption. Commenters

added that natural gas consumption in Arizona would increase from 900 MMcf/d in 2015 to over 

1,500 MMcf/d in 2020 and more than 2,500 MMcf/d by 2030. Commenters stated that the 

significant need for new pipeline infrastructure and capacity in a very short period of time will 

further strain already stressed natural gas infrastructure in the state.

Commenters stated that the already highly utilized and limited natural gas pipeline network 

serving Arizona, mainly El Paso and Transwestern pipelines, would require expansion by the 

early 2020s to account for the increased demand for natural gas by the power sector on top of 

expected demand growth in other sectors. Commenters added that based on modeling by PACE 

Global, the southern leg of the El Paso line is expected to exceed its current capacity by 2022 

and would require expansion by the early 2020s or sooner. Commenters stated that the northern 

El Paso line would require expansion by 2025. Commenters added that the Transwestern 

pipeline, which is already over 95 percent utilized, would also require expansion to serve any 

additional future demands.

Commenters stated that the development timeline to increase capacity is a minimum of 3 years 

with 4 or more years being a more reasonable estimate. Commenters concluded that this means 

that the expansion would need to begin as soon as Arizona's implementation plan is finalized in 

2017 to ensure reliable natural gas supply to the state.

Expansion of pipelines will be necessary. Commenters stated incremental natural gas demand 

resulting from the increased utilization of natural gas fired generation and the required new 

natural gas capacity needed to backfill the retired coal units to meet load would exceed the 

capacity of Arizona's existing, but already heavily utilized natural gas pipeline network. 

Commenters said Pace Global's analysis indicates that compliance with Arizona's interim goals 

would result in increased use of the El Paso system, as the alternate pipeline, Transwestern, is 

already 98% to 100% utilized; both the El Paso and Transwestern systems would require 

expansion by the mid-2020s to maintain adequate supply capacity. Commenters said pipelines 
82

require a minimum of four years lead time from need determination to in service date; the timing 

of the CPP goals would require these expansion projects to begin soon to meet demand. 

Other infrastructure needs. Commenters stated Building block 2 accounts for over 70% of 

Arizona's reduction required from baseline to its 2030 goal; the assumption that this generation 

switching could occur by 2020 is not feasible for Arizona due to in large part to the magnitude of 

investments in generation, transmission and pipeline infrastructure simultaneously, which require 

substantial commitments, permitting and construction lead times. Commenters said significant 

new infrastructure in the form of new electric transmission infrastructure, natural gas pipeline 

expansions, and generation infrastructure to maintain reliability would be needed. Commenters 

said further it would leave stranded investments in the state's existing coal fleet that would 

impact electric rates. 

Comment 42: AZ - Transmission system cannot support re-dispatch

Response 42: See section V.D. of the final rule preamble of the CPP for the EPA’s response to 

this comment and more information about Building Block 2. EPA believes its proposal and final 

CPP rate and goal requirements are fully compatable with resource adequacy, reliability, and the 

constraints of the current power grid as described in the Resource Adequance and Reliability 

Final TSD and section VIII.G.2 of the preamble.

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

Commenters stated that the Arizona transmission system cannot support re-dispatch.

Commenters stated that the electrical high voltage transmission system in Arizona has evolved 

over time and, in part, is designed to deliver power from remotely located power plants to the 

load. Commenters added that the Phoenix area is by far the largest load center in Arizona, 

representing about 62 percent of Arizona load. Commenters stated that it is served by a complex 

network of generation and transmission primarily owned and operated by APS and the Salt River 

Project Agricultural Improvement and Power District (SRP).

Commenters stated Arizona's coal-fired units are predominantly located to the northeast of the 

Phoenix load pocket while most of the NGCC units are located to the west and southwest of 

Phoenix. Commenters asserted that the re-dispatch of all of Arizona's coal-fired generation 

would change the way power flows and impact a significant portion of Arizona's transmission 

system. Commenters stated that this raises reliability concerns about the operation of the 

electrical transmission system. 

Commenters stated that one of the key measures of reliability of serving the Phoenix load pocket 

is Maximum Load Serving Capability (MLSC). Commenters clarified that this is the maximum 

amount of load that can be served assuming that all generation located inside the load pocket is 

operating at full capacity, and the transmission system is importing as much power as possible, 

without overloading any circuits. Commenters added that transmission and local generation 

resources are planned based on projected load and MLSC plus a reserve margin to account for 

contingencies. Commenters stated that based on APS's assessment, there currently is enough 
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existing and planned local generation and transmission to reliably serve the APS Phoenix load 

pocket into the 2020s. Commenters asserted that re-dispatch of the coal-fired EGUs, however, 

will reduce MLSC and jeopardize APS's ability to reliably serve the Phoenix load.

Commenters questioned the impacts to the regional transmission system if the generation from 

all coal-fired EGUs in Arizona were re-dispatched to the NGCC units by 2020 as envisioned in 

EPA's Proposal. Commenters stated that both the impacts on MLSC and impacts under light load 

conditions were evaluated. Commenters stated that using industry standard power flow tools and 

methods, the limiting elements and transmission system upgrades that would be needed to restore 

the MLSC to its present state and to mitigate high voltage levels occurring under light load 

conditions were identified.

Commenters stated that the analysis was conducted using the planned transmission configuration 

in 2020 and assuming the generation from the following coal-fired EGUs is re-dispatched to the 

NGCCs located in the state. 

Commenters stated that three cases were developed for the MLSC studies: BASE CASE - MLSC 

of the Phoenix load pocket with coal-fired generation on line, NO COAL - MLSC of the Phoenix 

load pocket after coal-fired generation re-dispatch, and NO COAL WITH UPGRADES - MLSC 

of the Phoenix load pocket with coal-fired generation re-dispatched, and overloads mitigated.

Commenters stated that the results of the MLSC study show that under the No Coal Scenario, the 

MLSC of the Phoenix Valley load pocket is reduced by 1,338 MW (from 16,321 MW to 14,983 

MW); the peak load plus margin value is 15,255 MW. Commenters concluded that this scenario 

results in a shortage of 272 MW.

Commenters asserted that assuming the actual peak load does not exceed the projected peak 

load, and if all generators and transmission lines are in service at the time of the peak, the load 

requirement is met and the shortage occurs in the margin value. Commenters warned that 

however, depending on what contingencies are occurring at the time of the peak, it is possible 

that the load may not be met.

Commenters stated that this analysis is a first cut at identifying the transmission impacts 

associated with the re-dispatch of Arizona's coal-fired EGUs. Commenters added that due to the 

magnitude of the transmission changes that would be necessary to resolve this situation, a more 

detailed engineering analysis would have to be performed. Commenters stated that therefore, the 

cost and time required to implement the required upgrades has not been confirmed. Commenters

concluded that however, preliminary cost estimates are in the hundreds of millions of dollars and 

the time to implement the transmission system upgrade will take years. 

Commenters stated the existing transmission network is designed for coal-fired EGUs located in 

the eastern and southern periphery of the State, while the NGCC EGUs are located in and around 

Phoenix and in the western periphery of the State. Commenters said significant modifications 

and additions to the transmission network would be required to account for shutdown of the 

coalfired EGUs and still provide reliable electricity. Commenters said it does not appear that 

these issues were included in the proposed timing of BB2 implementation in 2020.
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Commenters stated since the CPP requirements will not be finalized until mid-2015 and state 

implementation plans will not be approved by EPA until mid-2017 or later, timing of the final 

state plan approval and the typical five-year timeframe to site and construct new power plants 

would result in real reserve margin declines, noting the sharp decrease in coal generation 

required under Pace Global's analysis of the CPP Building Block scenario. Commenters said 

given these real world constraints, Arizona will need to seek relief from the CPP's interim goals 

in order to maintain grid reliability and security. Commenters said the EPA should include a 

reliability safety valve mechanism in the final rule; even if the interim goals are delayed or state 

goals reduced, there is still a risk to reliability. Commenters said consistent with impacts, the 

EPA should include in its final rule circumstances under which compliance can be delayed to 

manage real time issues that will compromise electric reliability. 

Comment 43: AZ - framework used by the EPA assumes electricity is bound by state lines - not 

accurate

Response 43: See sections VI, VII, and VIII.C. of the final rule preamble of the CPP for the 

EPA’s response to this comment. EPA has taken a regionalized approach to building block two 

in this final rule.

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

Commenters stated electricity is not bound by state lines - unlike the framework contemplated by 

the Proposal. Commenters said the Springerville facility is located in Arizona less than 10 miles 

from the New Mexico border, however the majority of power produced by Unit 3, which is 

owned by Tri-State, is used to serve Member System loads in rural Colorado and New Mexico. 

Commenters said the fact that there is excess natural gas-fired capacity within the borders of 

Arizona (which is why the coal-fired EGUs in Arizona must be shut down under the Proposal) 

does not mean that those natural gas plants can provide electric power to the residents of 

Colorado and New Mexico that Springerville Unit 3 currently serves. 

Commenters stated those excess natural gas-fired plants are located on the other side of Arizona 

largely to help provide electric power to residents in California and Nevada, and there is no 

reason to believe that the output of these units could be transmitted to Tri-State's Colorado and 

New Mexico customers, nor does Tri-State have any contractual rights to compel the owners of 

those plants to increase their output for the benefit of Tri-State. 

Comment 44: AR - Rule falls hardest on one of the poorest states

Response 44: See sections V.D VI and VII 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 proposed rule falls hardest on one of the poorest states (Arkansas).
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Commenters asserted that the rule as proposed will require Arkansas to meet an almost 45% 

reduction in carbon emissions from electric generating units ("EGUs") by 2030. Commenters

stated that this is the 6th highest rate of reduction in the nation, imposed upon a state that 

currently ranks 46th in per capita income. Commenters added that there can be no question that 

the proposed rule will have a huge impact on our state's utility rates, and these rate increases will 

disproportionally impact low income Arkansans. Commenters stated that this drastic reduction 

creates an economic inequity for Arkansas when compared with other states.

Comment 45: AR - The EPA's targets for Arkansas are achievable

Response 45: The EPA appreciates the comments of support for the proposed goals, please see 

Section V, VI, and Section VIII of the preamble for discussion of changes to the BSER between 

proposal and final based on comments and our further consideration, the quantification of the 

BSER in this final rule, and a description of the state goals.

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

Commenters asserted that EPA's targets for AR are achievable.

Commenters stated that in this section, they combined reasonable levels of re-dispatch, energyefficiency savings and renewable development to demonstrate the achievability of the EPA's 

emissions-reduction target for Arkansas. Commenters stated that they assumed the energyefficiency savings of the modest case. Commenters added that the generation requirement equals 

the state sales forecast used by the EPA, plus 10% losses and net exports, which are set at the 

out-of-state ownership shares of the coal plants (and which therefore decline as coal-plant output 

declines) .

Commenters stated that they assumed that in 2020, White Bluff retires, Turk capacity factor falls 

to 68%, and the capacity factors of the other three coal plants fall to the 30-35% range. 

Commenters stated that after 2020, they ramped down the capacity factors for the remaining coal 

plants, with Flint Creek retiring in 2027, Turk reaching 60% capacity factor in 2030, and the 

other plants reaching capacity factors near 20%. Commenters added that for the NGCC plants in 

2012, they assumed that Oswald and Fitzhugh operate as they did in 2012 (at 7% capacity factor 

and high emission rates), Pine Bluff operates as it did in 2012, and that the other four plants 

operate at an average capacity factor around 55%, based on nameplate rating. Commenters stated 

that thereafter, they ramped down the combined-cycle generation to keep total generation near 

the output requirement. Commenters added that they also ramped down the oil and gas steam 

generation, to reflect pending retirements and the effects of higher renewable generation. 

Commenters stated that for the "other generation" category (mostly combustion turbines), they

kept generation fixed at the average of 2012 and 2013 levels.

Commenters stated that the "Non-covered Generation" category includes the new renewables. 

Commenters added that the 2020 renewable capacity in each category is a small fraction of the 

potential estimated; other than wind imports, the same is true for the 2030 capacity. Commenters

stated that the timing of the renewables reflects the lead times, which are minimal for wind 
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imports from the Plains and for solar, with in-state wind and addition of capacity at existing 

dams taking longer for licensing, design, and construction. Commenters added that each of these 

categories of renewables can be developed faster to back down the NGCCs and/or support 

further reductions in coal use.

Commenters stated that applying emission rates by generation category yields an estimate of 

total emissions in the example compliance plan. Commenters added that on a mass basis, this 

plan would reduce emissions 41% by 2020, an average of 47% over 2020-2029 (compared to a 

target of 41%), and 54% in 2030 (compared to a target of 44%). Commenters stated that the 

average emission rate under the EPA formula would be about 878 lb/MWh for 2020-29 

(compared to the target of 968 lb/MWh) and 734 lb/MWh for 2030 (compared to a target of 910 

lb/MWh). 

Commenters stated that this compliance trajectory should be readily achievable. Commenters

added that the Arkansas DEQ can establish a SIP that exceeds the EPA goals, adopt a massbased target, assign emission allowances to each covered unit, and accept allowances from other 

states. Commenters stated that inclusion of allowance prices in planning and dispatch would 

result in reduced usage and/or retirement of coal capacity, while meeting local reliability 

constraints. Commenters added that if any one component of the compliance trajectory (four 

types of renewables, energy-efficiency programs, and increased output at four NGCC plants) 

were to be problematic, the generation owners would purchase more allowances, dispatch would 

shift more towards low- and no-CO2 resources, utilities can accelerate their energy-efficiency 

programs, and addition of renewables will be more attractive to utilities and more profitable for 

developers.

Commenters concluded that the EPA's targets for Arkansas are feasible. Commenters added that 

the more-modest reductions required of most other states should be equally achievable.

Comment 46: AR - goal recommendations

Response 46: For the EPA’s response to this comment, see the CO2 Emission Performance Rate 

and Goal Computation TSD for CPP Final Rule supporting the final CPP. EPA takes a 

regionalized approach to quantifying BSER in this final rule. It quantification of the building 

blocks shows a significant amount of fossil steam remaining online, and its compliance modeling 

does as well. There is no requirement that any specific unit (e.g., Plum Point) would be required 

to curtail generation.

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

Commenters requested that EPA incorporate the following positions and recommendations: 

The carbon reduction goals that EPA proposes for Arkansas are based on modeling that ignores 

practical limitations and real-world economic impacts. 

EPA should revamp its BSER modeling so that the carbon emissions goals established for each 

state reasonably reflect what is realistically achievable in the timeframe of the CPP. 
87

To the extent the Arkansas emissions targets would necessitate curtailed operations or the 

premature retirement of Plum Point, that outcome would impose profound economic harm on 

Mississippi -already among the most economically disadvantaged states in the nation - as well on 

as the several other states in which Plum Point's co-owners do business. 

EPA should extend the compliance deadlines in the CPP in order to mitigate the economic 

impacts of mandating adherence to aggressive reduction targets in a compressed period of time. 

EPA should require that state plans include a process to evaluate electric system reliability issues 

resulting from implementation of the state plan and require mitigation when needed. 

Comment 47: AR - goals

Response 47: For the EPA’s response to this comment, see sections VI and VII of the final 

preamble and CO2 Emission Performance Rate and Goal Computation TSD for CPP Final Rule 

supporting the final CPP. EPA has treated the Turk Plant as an under construction source in its 

baseline, and therefore adjusted its generation and emissions in the baseline upwards so the state 

totals better reflect its incremental impact.

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

Commenters stated Arkansas would be particularly hard hit by the proposed Clean Power Plan; 

in order to meet the 2030 target, Arkansas would need to reduce its carbon intensity by 44 

percent compared to 2012 reported carbon dioxide emissions. 

Commenters stated the reduction from actual carbon dioxide emissions will likely be even 

greater once Arkansas includes a full year of operation for the Turk power plant (Fulton, AR) 

that went into operation in December 2012. Commenters said the Turk plant is one of the 

cleanest, most-efficient coal plants in the country, and Arkansas is punished for that investment. 

Commenters stated in order to meet the 2020 interim target, which is only six years away, 

Arkansas may have to close 4 of its 7 coal-fired power plant units. Commenters said these power 

plants, once equipped with pollution control technologies to comply with MATS, CSPAR, and 

regional haze regulations, could operate for an additional twenty years; however, it is not likely 

that these coal-fired power plants would be modified for GHG emission reduction. Commenters

said therefore, the utilities that own these power plants may choose to close them prematurely, 

which could lead to reliability issues throughout the state. 

Comment 48: AR - Timing and Stringency of Goals. 

The 2030 Arkansas goal is technical flawed and unattainable in allotted time, goals may cause 

electric service disruptions in AR and affect electric service and cost in other states, interim goal 

will require too much reduction too quickly, insufficient natural gas pipelines and transmission 

resources currently exist and not feasible to construct new infrastructure by dates required.
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Response 48: See section I.A. of the final rule preamble of the CPP for the EPA’s response to 

this comment. See the Resource Adequacy and Reliability TSD. 

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

Several commenters said that the 2030 Arkansas goal, which is the sixth most stringent in the 

United States, is unattainable under the contemplated time frame. Commenters said further, the 

goal is technically flawed, and the actual emissions reductions needed to meet the goal will 

exceed the apparent 44% level, and without correction, these goals may threaten to cause electric 

service disruptions in Arkansas and may also affect electricity service and cost in other states. 

Commenters said that of equal importance is the fact that the Arkansas interim goal is almost the 

same as the final goal. Commenters indicated they understand that the EPA intends for the 

interim goal to allow the state - through the averaging of emissions across a series of individual 

years - to implement a flexible glide path to compliance in 2030. Commenters stated that, 

however, the Arkansas interim goal is so close to the 2030 goal that, based on a straight-line 

decline starting in 2020, the state would have to plan, seek approval for, and implement a suite of 

actions producing a CO2 emissions reduction of roughly 37% between 2016 and 2020. 

Commenters said that in practical terms, such a large undertaking in so short a time is 

unworkable, and added that any delays in meeting this near-term goal would essentially move 

the 2030 goal forward in time.

Commenters said that emissions reductions of this magnitude within less than four years imply a 

major, permanent change in the electricity operations within the state. Commenters said that the 

magnitude of the change in the case of Arkansas cannot properly be characterized as "redispatch", as the EPA has provided within the portion of the goal-setting formula that dominates 

the Arkansas goal. Commenters said that "dispatch" refers to a selection by a utility company or 

grid operator between existing generation resources to meet fluctuations in load. Commenters

said the Arkansas goal, by contrast, requires state regulators and EGU owners to take actions on 

a different time scale and with a fundamentally different effect. Commenters indicated the goal 

requires long-range, multi-utility resource planning that will likely permanently retire and 

replace major resources and will include major new policy initiatives. 

Commenters said there are insufficient natural gas pipelines and transmission resources to 

replace coal-powered generators with natural gas generators in Arkansas, and it is not feasible to 

construct new infrastructure by the dates required in the Clean Power Plan. Commenters also 

said it is currently unknown what cost may be involved in comprehensively redesigning the 

electric transmission system.

Commenters stated with respect to infrastructure, the proposed rule contemplates power supply 

changes that could require substantial investments in additional infrastructure over the multi-year 

compliance period to ensure reliability, particularly with respect to increased utilization of gas 

fired generation. Commenters asserted that it is important that the Commission continue its work 

to support the timely development of needed energy infrastructure."
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Commenters stated the timelines for "Transmission Planning Process" and "GI Transmission and 

Service Process", both of which require approximately eight and a half years; are showing an 

estimate of up to $2.3 million per mile for 345 kV transmission construction.

Commenters stated the carbon emission reductions proposed for Arkansas cannot be achieved in 

the timeframe of the CPP without causing significant economic disruption. 

Commenters said the carbon emissions goals that the CPP would establish for Arkansas are 

especially aggressive; in 2012, the amount of CO2 actually emitted by electric generating units 

in Arkansas was 1,634 lbs per MWH. Commenters said the CPP would require Arkansas to 

reduce the statewide rate of carbon emissions to 968 lbs for each MWh generated, averaged over 

the period 2020-2029, and to 910 lbs per MWh by 2030 - a 44% reduction from the 2012 

emissions rate and the sixth highest reduction proposed for any state; fully 68.5% of that 

modeled reduction is assumed by EPA to come through the reduced utilization of existing coalfired generation. 

Commenters stated the flaws in EPA's application of its BSER methodology to Arkansas are too 

numerous to list, but the more obvious examples of the problems in EPA's application of this 

method to Arkansas generally and Plum Point specifically include the following: 

a. EPA's consideration of regulatory impacts is incomplete. 

b. EPA's analysis fails to account for the massive infrastructure build-out the CPP would 

require. 

c. EPA's assumptions about efficiency improvements are not sound. 

Comment 49: AR-Load Growth Issues

Response 49: In regards to load growth considerations for determining subcategory-specific 

rates or state goals, EPA believes 2012 is a reasonable baseline expectation and does not expect 

aggregate generation levels from these sources to increase during the compliance period. 

Moreover, it assumes that the under construction units have either 55% or 60% of the utilization 

dedicated to non-replacement purposes – therefore, this generation is added to the 2012 

generation levels for existing sources.

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

Commenters said that because of Arkansas' lower socioeconomic ranking, Arkansas Municipal 

Power Association members that are experiencing load growth due to economic development 

should not be penalized as inefficient.

Comment 50: AR - The EPA's treatment of emissions from new coal fired EGUs that started in 

2012
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Response 50: Based on comments and further consideration, the EPA is treating units that 

commenced operation in 2012 as under construction and estimating a representative full year 

generation for the unit as a substitute for the partial year data reported in 2012. For the EPA’s 

response to this comment, see the CO2 Emission Performance Rate and Goal Computation TSD 

for CPP Final Rule supporting the final CPP. For the Turk Plant, EPA effectively assumes an 

incremental impact of 60% utilization. It further recognizes that this new coal plant may operate 

at even higher utilization levels. However, as noted by the commenters – some of this generation 

would have a replacement (rather than incremental affect). Therefore, EPA felt the 60% 

utilization rate was reasonable for adjusting the states emissions and generation upwards.

Additionally, EPA has taken a regional approach to quantifying building block potential in this 

final rule. Quantifying the reduction potential of BB2 and BB3 technologies regionally (instead 

of just in the state where located – as proposed), has the effect noted by commenters of bringing 

outlier states closer to the mean.

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

Commenters stated AR has two brand new coal-fired EGUs and one undergoing a major 

upgrade, each has remaining useful life that extends far beyond 2030 compliance 

date. Commenters said new plant emissions at Turk (limited operation in 2012) were almost 

completely excluded from goal-setting baseline; methodology to address this issue for Turk and 

other 5 coal-fired EGUs in nation that commenced operation in 2012 is presented.

Commenters listed the five coal-fired power plants (totaling seven EGUs) that are located within 

Arkansas: (1-Unit Flint Creek 558MW plant; 2-Unit White Bluff 1800MW plant; 2-Unit 

Independence 1800MW plant; 1-Unit Plum Point 720MW Energy Station; and 1-Unit John W. 

Turk 609MW power plant.) Commenters indicated that taken together, Turk, Plum Point, and 

Flint Creek represent 34% of the coal-fired EGU capacity in Arkansas. Commenters said that 

because two of them are brand new (Turk and Plum Point) and the third is undergoing a major 

upgrade (Flint Creek), each has a remaining useful life that extends well beyond the proposed 

2030 compliance date.

Commenters said the CO2 emissions from the normal operation of Turk are almost entirely 

omitted from the calculation of the initial Arkansas emissions baseline. Commenters explained 

that the Turk plant emitted less than 0.2 million tons of CO2 during 2012; during its first full 

year of operation (2013), however, it emitted 3.7 million tons of CO2. 

Commenters said that the effect of including a fully operational Turk plant in 2013 would make 

Arkansas' initial adjusted fossil rate 1,698 lbs CO2/MWh (1,793 lbs CO2/MWh unadjusted) as 

compared to 1,634 lbs CO2/MWh adjusted (1,722 lbs CO2/MWh unadjusted). Commenters said 

thus, if the 2012 goal-setting baseline is retained in its current form, Arkansas will have a higher 

actual initial emissions rate than contemplated in the compliance baseline, and will therefore be 

required to make significantly larger reductions than the EPA proposed within the formula. 

Commenters said this base year selection also would exacerbate the difficulty with meeting the 

interim goal and the implementation problems resulting from wide disparity among states. 
91

Commenters said that while it might seem reasonable to adopt instead a 2013 baseline, or a 

baseline that averages emissions from a series of years, they believe that those approaches would 

not reach the underlying problems highlighted by the addition of the Turk plant and its 

interaction with goal compliance for at least three reasons:

First, the addition of highly efficient, low-fuel-cost coal generation in part displaces other 

generation, including existing combined-cycle generation. Thus, in part because of the addition 

of the Turk plant, a 2013 baseline (and other future years) will reflect decreased NGCC 

utilization in Arkansas (indeed, avoiding reliance upon natural gas generation was the chief 

economic argument made to regulators to justify building the plant).

Second, because of differences between 2012 and 2013 in weather, electricity load, and fuel 

prices, it may be impossible to exactly quantify this effect within any single year, but even a 

small impact would significantly affect the Arkansas goal. This is because the EPA formula's 

Block 2 "re-dispatch" from coal to natural gas is by far the largest component of the Arkansas 

goal. The reduction in 2013 NGCC generation under the proposed formula caused by the 

combination of Turk generation, increased natural gas prices, reduced load, weather, and other 

effects would - if the proposed formula were applied to 2013 data - require even greater 

Arkansas emissions reductions, even though the real-world effect of the displacement of NGCC 

by new coal would make the reductions more difficult to achieve. A similar result would follow 

from using a 3-yeare average for baseline goal setting emissions.

A third, and more fundamental baseline issue, is that the interstate nature of the electricity 

generation and transmission system does not harmonize with the state-specific jurisdiction of 

state air environmental (and generally) utility regulators. The new Turk emissions were added to 

Arkansas, in significant part, to provide electricity over an interstate transmission system: for 

instance, the plant's owners include electricity suppliers in four states and its inclusion in retail 

electricity rates has recently been litigated in Texas and Louisiana.

Commenters said that a more reasonable approach would be to make adjustments to the formula 

that take into account unique situations and that tend to bring the outlier states towards the mean. 

Commenters said therefore, with respect to partial-year emissions from Turk, and perhaps the 

other five coal-fired EGUs nationally that commenced service during 2012, EPA should: 

Exclude the post-2012 share of annual emissions from the goal-setting formula on the basis that 

the remaining useful life of the plant clearly places it outside the proposed compliance period 

(much as EPA has already provided that a state may exclude the emissions from new combined 

cycle natural gas EGUs from Section 111(d) and account for them only under Section 111(b)). 

Alternatively, EPA could gradually phase-in the incorporation of Turk emissions for compliance 

purposes, recognizing these emissions through a higher allowed fossil emissions rate (perhaps 

based upon a straight-line annual percentage ranging from 0% to 100% over its full remaining 

useful life).

Comment 51: AR - financial implications of prematurely retiring Plum Point would be crippling
92

Response 51: For the EPA’s response to this comment, see the CO2 Emission Performance Rate 

and Goal Computation TSD for CPP Final Rule supporting the final CPP. EPA BSER 

quantification of source category rates and its final RIA modeling suggest that coal generation is 

a very significant portion of the generation portfolio mix in a BSER scenario. The Final, nor 

proposed, CPP would not require units like Plum Point to curtail operation. 

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

Commenters stated that financial implications of prematurely retiring Plum Point would be 

crippling.

Commenters stated that in developing their reduction goals, EPA forecasted the retirement of 

Plum Point by 2020 and this makes absolutely no sense. Commenters asserted that there are 

hundreds of coal-powered electric generators in the United States and on average, they are over 

40 years old. Commenters stated that Plum Point is a new and efficient coal plant that was first 

energized in 2010. Commenters added that it is equipped with the extensive environmental 

controls that were mandated for new plants when it was constructed. Commenters stated that 

Plum Point represents one of the largest investments that our community has ever made. 

Commenters concluded that the financial implications of prematurely retiring Plum Point, or 

reducing its output for environmental compliance, would be crippling to North Little Rock and 

other Arkansas cities.

Comment 52: 6% HRI is not reasonable for Arkansas; states should be allowed to calculate 

their own BB1 goal by evaluating specific facilities or the EPA should set an average net heat 

rate (BTU/kWh) for all affected EGUs for BB1 goal setting; the BB1 goal setting formulas 

should be modified for new and newly modified units, and should recognize that environmental 

control projects reduce HRI opportunity

Response 52: See section V.C. of the final rule preamble of the CPP for the EPA’s response to 

this comment and more information about Building Block 1. Section 3.1.4 of this RTC 

document discusses the interation between expected control and BB1 assumptions.

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

Commenters said that in setting a state's emissions rate reduction target, the EPA has proposed 

reducing emissions rates at existing coal-fired units based on a uniform average of 6% HRI that 

is derived from a national study. Commenters said that the EPA, further, inappropriately applied 

an analysis of gross heat rate data to a net heat rate goal. Commenters said it is impractical and 

unreasonable for the EPA to assign an average HRI to states irrespective of the ability of a 

particular state's EGUs to make that HRI, and the resulting HRI goal does not reasonably apply 

in Arkansas. Commenters also indicated that Arkansas has limited ability to increase the overall 

efficiency of coal-powered generators because two of the six coal plants in Arkansas are the 

newest and most efficient in the nation, and the remaining have little if any ability to improve the 

efficiency of their coal-fired generators.
93

Commenters said the newest facility, the Turk plant, is the only ultra-supercritical coal-fired 

EGU and is the most fuel-efficient coal-fired EGU in the U.S. Commenters said the secondnewest plant, Plum Point, began commercial operations in the latter part of 2010. Commenters

said that based upon information provided by Southwestern Electric Power Company and Plum 

Point, these newer EGUs will not be able to achieve any appreciable HRI. Commenters said 

given the lack of opportunity for HRI at those two facilities, the remaining five Arkansas coalfired EGUs would need to implement HRI exceeding 8% in order to meet the 6% HRI goal. 

Commenters said information provided by Entergy to the commenters indicated that if all of the 

items identified by Sargent and Lundy's report that could be implemented at the Independence 

and White Bluff facilities were fully implemented, the average HRI would be 2% to 4%. 

Commenters said thus, Arkansas' newer plants will likely not see any significant improvements 

or only trivial improvements in heat rate, and our older plants probably cannot achieve greater 

improvement beyond the design heat rate. 

Commenters said further, the Flint Creek unit is being retrofitted with additional emission 

control equipment to comply with the Mercury and Air Toxics Standards (hereinafter "MATS") 

and Regional Haze rules. Commenters said the new equipment will increase the Flint Creek 

unit's heat rate above the 2012 base year heat rate, thus decreasing its efficiency. Commenters

said this environmental control project will thus likely reduce the available HRI assumed for 

Arkansas in Block 1.

Commenters said that for the purpose of goal-setting the EPA should recognize that:

Currently un-scrubbed units which continue to operate at base-load levels will likely be required 

to implement controls that will create parasitic loads that will partially negate the theoretical 

benefits of investments in HRIs (commenters noted such units comprise 76% of coal-fired EGU 

capacity in AR).

The reduced coal EGU operations envisioned in Block 2 of the Proposed Rule will likely erode 

the operating efficiency of these EGUs.

Commenters indicated the heat rate ranking of Arkansas coal-fired EGUs among coal-fired 

EGUs nationally according to the 2012 EIA form 923 annual dataset and the 2013 EIA form 923 

monthly dataset. Commenters said it confirms that Turk is the most efficient coal-fired EGU in 

the U.S. and suggests that it is unlikely that the Arkansas plants have the potential for the same 

level of cost-effective HRI improvements, on average, as plants in other states, since over half of 

the coal-fired capacity in Arkansas is most recently among the top 100 plants nationally for heat 

rate. 

To address these BB1 HRI calculation and goal setting concerns:

Commenters said EPA should allow Arkansas (and other states) to calculate its Block 1 goal by 

evaluating their specific facilities' actual opportunities for efficiency measures at their respective 

EGUs

Commenters said alternatively, instead of focusing on the percentage HRI, it may be more 

practical to set an average net heat rate in BTU/kWh for all affected EGUs (a method similar to 

traditional New Source Performance Standards) for Block 1 goal-setting. 
94

Commenters said the EPA should exclude Turk's and Plum Point's capacity from any assumption 

in the Final Rule that all plants within Arkansas can be made more efficient.

Commenters said similarly, the goal-setting formula should be amended to take into account at 

least the bright-line cases where remaining useful life precludes near-term retirement, such as 

plants that came into operation during and after 2010, and those currently undergoing major 

environmental control projects. 

Commenters said the 2012 baseline assumptions should be adjusted to recognize the fact that 

environmental control projects occurring post-2012 will worsen heat rates, reducing the available 

opportunity for HRIs.

Comment 53: AR - BB2 input data discrepancies and suggested changes to treatment of CHP 

facilities

Response 53: See section V.D. of the final rule preamble of the CPP for the EPA’s response to 

this comment and more information about Building Block 2 and see the CO2 Emission 

Performance Rate and Goal Computation TSD for CPP Final Rule supporting the final 

CPP. Consistent with commenters suggestion, and as discussed in section VI of the preamble, 

EPA no longer includes useful thermal output when quantifiying BSER. Therefore, the NGCC 

2012 NGCC rate for existing sources (those commencing operationg before 2012) in the state is 

896 lb/MWh in EPA’s final calculations.

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

Commenters said discrepancies in actual emissions rates for AR facilities, in combination with 

other methodological issues regarding BB2 and treatment of CHP facilities, establishes 

unreasonable interim and final goals for Arkansas.

Importance of BB2 for AR goal-setting. Commenters indicated that Arkansas is among a 

handful of states for which the assumptions underlying Block 2 are the most important goalsetting issue: 67% of the required 2030 reductions from Arkansas' adjusted 2012 baseline 

emissions rate, and 73% of the 2020-2029 rate reductions from the adjusted 2012 baseline, stem 

from Block 2. Commenters said although a state is allowed to over-comply with one building 

block (BB) to offset under-compliance with another BB, in the case of Arkansas so much of the 

goal is dependent on Block 2 that a significant shortfall in Block 2 compliance likely cannot be 

made up through the relatively small potential that the EPA foresees in Arkansas from the other 

Blocks, particularly in the case of short-term compliance with the interim, goal.

Data Discrepancy. Commenters said the goal-setting formula establishes an imputed average 

emission rate for NGCC plants within Arkansas of 827 lbs CO2/MWh. Commenters said this 

average is based upon the amount of generation and the amount of emissions during 2012 for 

seven NGCC power plants. 

Commenters said every NGCC plant in Arkansas has an actual emissions rate that is higher than 

the adjusted NGCC emissions rate imputed to Arkansas for existing NGCC. Commenters said an 
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adjustment to the actual emissions rate for a single plant (PBEC) significantly lowers the 2012 

fleetwide average NGCC emissions rate. Commenters said the formula then carries forward this 

imputed average to project total NGCC fleet emissions after "re-dispatch". Commenters said 

carrying this imputed emissions rate through Block 2, which is the single largest factor in the

goal-setting formula for Arkansas, misrepresents the effect of "re-dispatch" on CO2 emissions. 

Methodology used for Combined Heat and Power (CHP). Commenters said the EPA's treatment 

of CHP, and particularly the emissions from PBEC, unrealistically lowers the Arkansas NGCC 

fleetwide CO2 emissions rate during the 2012 baseline year, thereby skewing the baseline and 

re-dispatch assumptions.

Commenters said the PBEC is the only CHP facility in Arkansas that is included within the 2012 

NGCC baseline emissions rate (and thus in the Block 2 assumptions about re-dispatch for 

individual state goal-setting). Commenters said that PBEC is a 236 MW facility, comprising less 

than 5% of the total NGCC capacity in Arkansas.

Commenters said that according to EPA data, PBEC's actual CO2 emissions rate during 2012 

was 1,132 lbs CO2/MWh - 37% higher than the EPA-imputed fleet wide average emission rate 

for NGCCs. Commenters said however, because PBEC is a CHP plant, the EPA accounts for its 

useful thermal output ("UTO"), attributing an emissions reduction to this useful heat. 

Commenters said through that attribution, PBEC is accorded an adjusted emissions rate of 602 

lbs CO2/MWh - 28% better than any other NGCC in Arkansas.

Commenters said that removing UTO from the goal computation would increase the fleet-wide 

NGCC emission rate by 8% and reduce the stringency of the overall Arkansas 2030 goal by 6%. 

Commenters said that the EPA's treatment of this one existing industrial cogenerator within the 

goal-setting formula thus could significantly steer statewide public utility planning through 2030, 

having an impact similar in magnitude to the EPA's assumptions regarding RE, EE, or statewide 

HRIs for coal EGUs.

Commenters said that because PBEC is an industrial cogeneration facility, it generally runs to 

provide electricity and heat to its host paper mill, regardless of whether fuel prices and load 

conditions within the broader power market lead to a low or high level of annual dispatch for 

other NGCCs. Commenters said that during 2012, when every other NGCC in Arkansas ran less 

than half the time, PBEC operated on average at 72% of its nameplate capacity.

Commenters said the goal-setting formula creates a weighted average including PBEC running 

during 2012 at 72% capacity and the other (generally larger) NGCC generators running at 

capacity factors of 7% to 47%.

Significant percentage of total NGCC capacity in AR had low capacity factors in 2012. 

Commenters said that four NGCC plants ran very little during 2012, at utilization factors ranging 

from 7-12%. Commenters said these plants have almost 2180 MW of capacity, forming almost 

40% of the total capacity among affected NGCC units in Arkansas. Commenters added that these 

units had 2012 CO2 emissions rates between 11% and 37% higher than the EPA-imputed 

average of 827 lbs CO2/MWh, in part because of their low utilization rate.
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Commenters said that in addition, two large plants comprising almost 3,200 MW - 57% of total 

affected NGCC nameplate capacity - ran a little less than half the time during 2012. Commenters

said these NGCC plants had 2012 emissions rates above the 827 lbs CO2/MWh EPA-imputed 

average, with the bulk of the capacity being 5% less efficient than EPA's average.

Capacity of PBEC was more than 70% in 2012. Commenters said finally, PBEC comprised the 

remaining capacity and ran over 70% of the time during 2012, and said it is the only plant with 

an adjusted emissions rate - based on useful thermal output - below the fleet average. 

Commenters said PBEC's adjusted emissions rate is 27% below the EPA-imputed average.

Goal-setting Assumptions and Implications. Commenters said that under the EPA's goal-setting 

assumption, all of these plants would run, on average, 70% of the time. Commenters said that 

under that scenario, it is clear that substantially all of the increase in NGCC generation would 

come from the roughly 40% of NGCC capacity with much higher 2012 emissions than the EPA 

average and the roughly 60% of NGCC capacity with slightly higher 2012 emissions than the 

EPA average. Commenters indicated the single plant with lower emissions (PBEC) is already 

above 70% capacity utilization and would contribute little or nothing to 70% average operations, 

even if it were to run 100% of the time.

Commenters said that absent an adjustment to remove UTO from the imputed average Arkansas 

emissions rate, it is thus unrealistic for the EPA to assume that average emissions in Arkansas at 

the 70% NGCC utilization rate will match the adjusted NGCC emissions rate assigned to 

Arkansas in the goal-setting formula. Commenters said rather, if the EPA does not omit imputed 

UTO from the Arkansas average emissions rate, then the actual fleetwide NCGG emissions rate 

at 70% NGCC capacity utilization will likely significantly exceed the EPA-imputed rate,

impairing Arkansas' compliance with the goal.

Suggested Modifications to Treatment of CHP. Commenters said they do not oppose accounting 

for useful heat input for CHP plants in section 111(d) compliance plans. Commenters said that 

increased use of highly-efficient CHP in appropriate applications can be a significant, useful and 

realistic strategy to reduce CO2 emissions. Commenters also said that disproportionately 

weighting existing CHP within the 2012 baseline, however, does not serve this purpose and 

severely distorts the real effect of increasing utilization of existing NGCC capacity.

Commenters said that excluding the UTO from PBEC in the goal-setting formula would yield an 

Arkansas fleet-wide NGCC emission rate of approximately 896 lbs CO2/MWh, rather than the 

EPA-imputed 827 lbs CO2/MWh. Commenters suggested that to the degree that the non-PBEC 

generation is actually available at the level assumed by the EPA, this would be a more realistic 

representation of the effect of the re-dispatch envisioned in Block 2.

Commenters said another way to address useful UTO from PBEC would be to use the sum of 

plant - specific emissions from NGCC units after re-dispatch in the goal computation formula. 

Commenters said the "NGCC rate x Re-dispatched NGCC generation" term in the numerator of 

the goal computation formula would be replaced by the sum of unit-level emissions from NGCC 

units after re-dispatch. Commenters said unit-level NGCC emissions after re-dispatch can be 

calculated by multiplying plant-specific emission rates by unit-level generation expected at 70% 

capacity utilization for each unit.
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Commenters said that properly accounting in this way for plant-specific emissions and UTO 

from the NGCC units in Arkansas yields a significantly different overall emissions rate goal.

Comment 54: AR - Effect of NGCC utilization patterns on rate

Response 54: See section V.D. of the final rule preamble of the CPP for the EPA’s response to 

this comment and more information about Building Block 2. See response 53.

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

Commenters said that the EPA should develop a method for calculating BSER under BB2 which 

is not skewed by outlying emission rates from NGCCs due to useful thermal output or low 

utilization with frequent startups and shutdowns.

Commenters stated that a further complication of using a historical 2012 NGCC rate in the goal 

computation is that emission rates from individual units are likely to change if units that were 

largely inactive during 2012 are ramped up to 70%. Commenters said NGCC units that are 

currently used to follow load are cycled on and off more frequently than they would if these units 

were used for base load. Commenters said that NGCC units at facilities which were operated at 

less than 12% of their capacity over the 2012 baseline period, such as Dell, Fitzhugh, Oswald, 

and Hot Spring, may achieve lower emission rates if ramped up to 70% capacity utilization. 

Commenters stated that the EPA should develop a method for calculating BSER under Block 2 

which is not skewed by outlying emission rates from NGCCs due to useful thermal output or low 

utilization with frequent startups and shutdowns. 

Comment 55: AR - Nameplate versus summer-rated capacity

Response 55: The final rule uses net summertime NGCC capacity rather than nameplate 

capacity. 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:

Several commenters said that the EPA has overestimated the total capacity of Arkansas' NGCC 

units by assuming they operate at nameplate boiler capacity during the summer months.

Commenters said that the EPA should take into account the summer-rated capacity (perhaps by 

incorporating average humidity and summer temperatures for a Region) when assuming potential 

NGCC capacity. Several commenters said NGCC units in Arkansas are not able to operate at the 

stated nameplate boiler capacity during summer months, in part due to atmospheric conditions, 

and therefore, the EPA has overestimated the total capacity of Arkansas' NGCC units.

Commenters said the most efficient NGCC plant in Arkansas, Magnet Cove, for instance, has a 

nameplate capacity of 746 MW, but a summer-rated capacity of 642 MW - almost 13% lower 
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than the nameplate capacity. Commenters said the largest NGCC in Arkansas is Union Power. 

Commenters said the U.S. Energy Information Administration (hereinafter "EIA") records Union 

Power's nameplate capacity as 2,428 MW, but its summer-rated capacity (2,020 MW) is almost 

17% lower than its nameplate capacity. Commenters said that these two plants are perhaps the 

most likely to see increased operations under a scenario like EPA's Block 2.

Commenters said according to EIA, Arkansas' NGCC affected fleet nameplate capacity was 

5,588 MW. The EIA NGCC affected fleet summer-rated capacity was 4,661 MW - a difference 

of roughly 16%, or over 900 MW. 

Commenters said they understand that the EPA bases Block 2 goal-setting on nameplate capacity 

in part because summer-rated capacity may be more difficult to define in a manner that is 

uniform nationwide. Commenters indicated they also understand that the Block 2 "re-dispatch" is 

essentially an energy-based, rather than capacity-based assumption. Commenters said these 

considerations do not, however, obviate the reality that significantly less existing NGCC capacity 

is reliably available in Arkansas. Commenters reiterated, the Block 2 "re-dispatch" dominates 

the EPA goal-setting for Arkansas, and the EPA should adjust the Arkansas goal to take into 

account the actual reduction in annual energy generation that results from lower available 

summer NGCC capacity. 

Comment 56: AR - If air permit limitations prevent NGCC from reaching 70% utilization, then 

the reduced capacity limitation should be used in BSER determination

Response 56: See section V.D. of the final rule preamble of the CPP for the EPA’s response to 

this comment and more information about Building Block 2. EPA does not assume unit-level 

requirements or adjustments when quantifying the building blocks, rather it assumes the building 

block levels reflect a regional reduction potential that can be achieved on average across the 

regional NGCC fleet (in the case of BB-2). No unit is required to operate at a particular 

utilization level. 

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

Commenters said that if a facility has permit limitations limiting a NGCC from reaching 70% 

capacity utilization, the reduced capacity utilization should be used in the EPA's BSER 

determination.

Commenters said that the EPA includes the full nameplate capacity of the 600 MW Oswald plant 

within Block 2 of the goal-setting formula. Commenters said that because Oswald operated at 

less than 7% capacity utilization during 2012, its remaining capacity contributes substantially to 

the Arkansas goal.

Commenters said that according to the owners of the Oswald plant (Arkansas Electric 

Cooperatives Corporation, hereinafter "AECC"), its current Title V air permit includes NOx 

emissions limitations that effectively limit the operation of the plant to a 60% capacity factor. 

Commenters said operating Oswald in excess of these limitations may require a new permit that 
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might necessitate physical improvements to the plant to conform to Prevention of Significant 

Deterioration air quality regulations.

Commenters said that AECC's Fitzhugh plant is another Arkansas NGCC plant with air permit 

limitations. Commenters said specific conditions within the plant's air permit limit natural gas 

usage to 9.6 billion cubic feet based on an annual rolling average, which according to 

AECC, translates to a maximum annual capacity factor of about 63%. 

Commenters said that if the EPA chooses to include facilities with permit limits that prevent a 

facility from reaching 70% capacity utilization in the BSER determination, it should utilize a 

capacity factor that does not exceed currently permitted levels.

Comment 57: AR - Unit-level data discrepancies and methodology deviations

Response 57: See section V.D. of the final rule preamble of the CPP for the EPA’s response to 

this comment and more information about Building Block 2. The EPA used the methodology 

described in Appendix 9 of the CO2 Emission Performance Rate and Goal Computation TSD for 

CPP Final Rule supporting the final CPP to assign unit-level net generation and emissions. EPA 

followed this methodology because the information was not available to determine exact matches 

between units and generators. Because BSER quantification works at the regional and state 

level, and the total emissions and total generation from the facility are the same (regardless of 

unit-level apportionment), this data limitation typically has no influence on the the aggregate 

totals used. For instance, at Union Power plant referenced below, all of the NGCC are 

categorized as likely affected so the collective reported generation and emissions from the 

facility that goes into BSER quantification is the same (e.g., 4.3 million short tons), regardless of 

how it is apportioned to the unit-level. The same holds true at the generation level (e.g., 9.91 

TWh for this plant). The EPA examined the commenters’ attachments, but it was not clear how 

or why they believe this results in a difference to the Arkansas goal in these instances. The only 

instance where this limitation may become of relevance is where some units at the plant are 

considered affected, and some are not. However, this does not appear to be of central concern 

with the plants listed below. Based on a review of the commenters attachments, it appears the 

implication may be that it somehow impacted the “other emissions” associated with UTO. 

However, in this final CPP rule, EPA no longer includes useful thermal output in its goal 

computations.

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

Commenters said that in the EPA's "Data File: 2012 Unit-Level Data using the eGRID 

Methodology" dataset, the EPA used aggregate data rather than generator-specific data for

NGCC units, which may deviate from the methodology described in the "Description of 2012 

Unit-Level Data using eGRID Methodology" Technical Support Document (hereinafter "TSD"). 

Commenters said that in analyzing the EPA's "Data File: 2012 Unit-Level Data using the eGRID 

Methodology" dataset, they note that certain data elements appear to be derived without 

following the methodology (including the methodology for data priority) described in EPA's 

"Description of 2012 Unit-Level Data Using eGRID Methodology" TSD. Commenters said 
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specifically, the EPA aggregated Combined Cycle Steam Part (hereinafter "CA") and Combined 

Cycle Combustion Turbine Part (hereinafter "CT") data before performing calculations, instead 

of using available generator-specific data or performing prime-mover-specific calculations. 

Commenters said that this resulted in loss of generator- specific accuracy and misapplication of 

data priority as described in the TSD at the following facilities:

• Dell Power Station generator units CTG1, CTG2, and STG

• Harry L. Oswald generator units 1-9

• Hot Spring Generating Facility CT1, CT2, and Steam Turbine (hereinafter "ST")1

• Magnet Cove Gas Combustion Turbine (hereinafter "GCT")1, GT2, and ST1

• Pine Bluff Energy Center generator units CT01 and CT02

• Thomas Fitzhugh generator units 1 and 2

• Union Power Partners LP generator units CTG1 - CTG7 and STG1 - STG4 

Commenters stated that while this treatment of NGCC data may seem negligible at a facility 

level, the cumulative effect would have a 26 lb/MWh difference in Arkansas' final goal. 

Commenters said that additional discrepancies between the EPA's "2012 Unit-Level Data using 

eGRID Methodology" dataset and the values that ADEQ compiled when replicating the 

methodology described in the "Description of 2012 Unit-Level Data using eGRID Methodology" 

TSD can be found in the attached spreadsheet. 

Commenters said they seek clarification on the rationale behind the EPA's departures in the 

methodology used to derive generation and emissions data for these units from the methodology 

as described in the "Data File: 2012 Unit-Level Data using the eGRID Methodology" TSD. 

Commenters said that in addition, any necessary corrections to the dataset should be made before 

this data is used in the final goal computation for Arkansas.

Comment 58: AR - The EPA should establish a ramp rate for re-dispatch to NGCC

Response 58: See section V.D. of the final rule preamble of the CPP for the EPA’s response to 

this comment and more information about Building Block 2.

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

Commenters supported a more gradual phase-in of Block 2 to take into consideration current 

infrastructure feasibility and the overall magnitude of re-dispatch and the degree to which it 

affects the book life of new and recently modified coal-fired EGUs.

Commenters said that in the October 28, 2014 NODA, the EPA sought comment on a more 

gradual phase-in of Block 2 which considers the amount of utilization shift to NGCC feasible by 
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2020 then grows NGCC utilization to the full target based on the timing needed to build out new 

infrastructure to support the target utilization. Commenters said the magnitude of redispatch 

from NGCC to coal that is indicated in the goal-setting formula for Arkansas is more consistent 

with long-term resource planning decisions than with what are commonly considered dispatch 

decisions. Commenters said this is because the amount of generation shifted within the formula 

(equal to approximately 64% of the generation from the five coal- fired power plants that 

operated in Arkansas during some or all of 2012) reasonably would be expected to cause 

retirement of a significant portion of these units. Commenters added that such compliance also 

would likely impair the remaining useful life of one or more coal- fired EGUs such as Turk, 

Plum Point, and (potentially, upon retrofit) Flint Creek, and might require natural gas or 

transmission infrastructure upgrades. 

Commenters supported the consideration of current infrastructure feasibility and the use of a 

growth rate grounded in realistic timeframes for additional infrastructure deployment for Block 

2. In addition, Commenters suggested that the EPA should establish a threshold above which redispatch cannot reasonably be assumed to occur during the time between state plan approval and 

2020. Commenters said the threshold should take into account at least (a) the overall magnitude 

of redispatch and (b) the degree to which it affects the "book life" of those coal-fired EGUs that 

became operational since 2010. Commenters said the threshold also could take into account the 

effect on EGU remaining useful life of environmental controls retrofits underway at the time of 

the publication of the Proposed Rule. Commenters said above this threshold, Block 2 should then 

be phased in, in a manner similar to Blocks 3 and 4. 

Comment 59: AR - Most RE options are impractical in AR because of inadequate wind and 

solar capacity, attainment of the RE goal for Arkansas will depend largely on access to RE from 

other states, the EPA should provide a clear RE credit compliance pathway and additional 

guidance regarding interstate trading.

Response 59: See section V.E. of the final rule preamble of the CPP for the EPA’s response to 

this comment and more information about Building Block 3. See section VIII of the final 

preamble for discussion of ERCs and compliance pathways. 

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.

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

Arkansas and Associated Regional RE Goal

Commenters said the goal-setting formula assigns a 20% RE goal for an EPA-designated "South 

Central" region (Arkansas, Kansas, Louisiana, Nebraska, Oklahoma, and Texas). Commenters

said renewable generation for each state in the region is assumed to grow towards this goal, from 

its current share of non-hydro renewable generation, at an EPA-assigned 8% annual growth rate. 

Commenters stated that the application of this growth rate to current levels of renewable 

generation (rather than the 20% regional goal itself) yields the operative Arkansas goal of 7% 

renewable generation by 2030 and 5% for the interim goal period. Commenters said that 
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reasonable attainment of this goal using currently demonstrated technology, however, depends 

largely on access to renewable generation from other states that Arkansas cannot, under the 

proposed rule, guarantee through its own action.

Commenters stated that most renewable energy options are impractical in Arkansas because of 

inadequate wind and solar capacity based primarily on topographic constraints. Commenters said 

that solar energy projects in Arkansas have not performed as well as renewable energy projects 

in other states, and generally wind energy projects in Arkansas are not feasible.

Distribution of On-Shore Wind Resources in EPAs South Central Region

Commenters noted that regarding the proposed 20% regional goal, the EPA's "South Central" 

region contains two distinct categories of states for the purpose of RE. Commenters said the first 

includes Kansas, Nebraska, Oklahoma, and Texas - these states have among the best wind 

energy resources in the United States. Commenters said that generally, wind energy makes up by 

far the largest share of demonstrated, non-hydro, renewable generation, and consequently, the 

availability of wind resources is a significant determinant of the demonstrated non-hydro 

renewable resources available to any state.

Commenters said the second category of states within the EPA-designated South Central region 

includes Arkansas and Louisiana, and these two states simply do not have the same level of onshore wind resource. Commenters said this bright-line distinction means that in Arkansas it 

currently is significantly less costly for a utility to negotiate a Purchased Power Agreement 

(PPA) to generate and deliver wind energy from one of the windier states than to construct 

utility-scale wind generation in Arkansas. Commenters said the strongest evidence of the 

contrast between the wind resource in Arkansas and the neighboring windy states that EPA 

grouped it with is that while every electric investor-owned utility (hereinafter "IOU") or 

generation-owning cooperative within Arkansas either includes, or is considering wind PPAs 

within their generation portfolios, there is not a single utility-scale wind farm in Arkansas. 

Commenters stated that Arkansas utilities currently buy wind energy primarily from Oklahoma 

and Kansas on the basis of cost, and without the requirement of a state Renewable Energy 

Standard. Commenters stated in a comparison of RE technical potential for each of the states in 

the South Central region the differences are due primarily to estimated wind resources.

Recommendations for Determining RE Goals in AR

Commenters said that because imported wind energy is important to the cost-effective attainment 

of the RE goals proposed within BSER, they make the following recommendations: 

A. EPA should provide a clear RE credit compliance pathway.

More specifically, EPA should clearly credit renewable generation based upon out-ofstate PPAs in a manner that does not depend on Arkansas negotiating agreements with 

neighboring states; and

EPA also should credit increased, customer-sited distributed renewable generation within 

a state, which is implemented after the date of the publication of the Proposed Rule, 

similarly to its proposed treatment of end-use EE. 
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B. Particularly, in the case of net-metering for zero-carbon RE, the EPA should provide 

an acceptable standard method of converting installed capacity to generation, and/or 

method(s) for measuring generation for net-metering customers.

Other Needs and Recommendations

Checklist for compliance through interstate trading. Commenters also recommended that the 

EPA provide the states with a template (or checklist) containing all the required components for 

plans that rely on interstate trading to comply with the rates, in order to reduce the burden on 

states that either develop a state-only plan or pursue an interstate trading plan for compliance, 

while providing a platform to streamline the EPA's review of Section 111(d) plans. 

RE goals based on economic potential and demonstrated RE. Commenters said that if the Final 

Rule continues merely to allow for interstate cooperation in the counting of RECs and out-ofstate PPAs, but does not make these tools available to states as a unilateral right, then they 

recommend that RE goals for each state be based upon the technical and economic potential for 

demonstrated RE generation within each state, rather than upon a regional average that assumes 

interstate cooperation. 

Need for EPA to develop state-specific technical and economic pathway. Commenters said that 

on page 7 of the "Alternate RE Approach TSD", the EPA suggests such a potential alternative 

method for goal-setting that would calculate technical and economic potential. Commenters said 

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 the 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 the EPA. 

Compliance risk for states with no 'at-risk' nuclear generation. Commenters said that the EPA 

proposed as part of Block 3 that states with nuclear generation be eligible to receive credit for the 

carbon savings associated with keeping 6% of "each state's historical nuclear capacity" in 

operation. Commenters said the EPA's 6% assumption is based upon a percentage of total U.S. 

nuclear power generation that the EPA deems to be at risk of retirement. Commenters said that 

Arkansas does not anticipate any nuclear plant retirement during the time period contemplated 

for compliance, thus its nuclear generation is not "at risk." Commenters said that the EPA should 

reevaluate the BSER calculations regarding states with nuclear generation that is not "at risk," as 

the national percentage is not a uniform national trend and the EPA's standing assumption 

creates a compliance risk for those states. 

Biomass fuels should be treated same as other RE technologies in goal setting. Commenters said 

that for states such as Arkansas with rich renewable forest resources, biomass energy would 

provide a significant portion of projected renewable energy. Commenters added that Arkansas' 

starting level of performance value in the EPA's proposed goal-setting formula is based solely on 

biomass and wood-derived fuels generation reported to the Energy Information Administration 

(hereinafter "EIA"). Commenters said that combusting biomass for energy does not produce a 

one-for-one increase in net CO2 emissions because biomass is part of the natural carbon cycle. 

Commenters said that for this reason, and because the EPA applies the renewable energy annual 
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growth in the goal-setting formula to existing biomass generation, biomass fuels should be 

treated in the same way as other renewable products, such as wind and solar, for compliance 

purposes. 

Comment 60: AR - Proposed rule needs to account for annual CO2 emissions for Turk Plant

Response 60: The EPA has flagged the Turk Plant as under construction in 2012, and adjusted

the state’s coal generation and emissions upwards reflecting a representative full year of 

operation for the plant. For the EPA’s response to this comment, see the CO2 Emission 

Performance Rate and Goal Computation TSD for CPP Final Rule supporting the final CPP.

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

Commenters said that the John W. Turk, Jr. power plant commenced operation in December 

2012, and a full year of CO2 emissions for the facility should be accounted represented in the 

EPA database.

Commenters said the John W. Turk, Jr. Power Plant ("Turk") began commercial operation on 

December 20, 2012, and therefore, the only CO2 emissions in the EPA's database for 2012 were 

startup emissions and ten operational days for Turk. Commenters said by contrast, in 2013, Turk 

operated in a manner that the commenters considers a typical year for a baseload, coal-fired 

power plant, i.e. all year long.

Commenters said the emissions from Turk must be factored into the baseline emissions levels in 

order for the proposed Rule to accurately capture the status quo. Commenters said that because 

the 2012 baseline is not a representative sample as it pertains to Turk (or other factors, for that 

matter), the commenters proposes a substitution of calendar year 2013 values, in lieu of 2012 

values, for Turk in the eight-year average (2005-2012) proposed in a prior comment

Comment 61: AR - Arkansas is an exporter of coal-fired generation; the costs to reduce 

emissions should fall on the out-of-state utilities

Response 61: See section V.III.C. 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 Arkansas is an exporter of coal energy, and the costs of reducing 

emissions from Arkansas's coal fleet should fall heavily on the out-of-state utilities with 

entitlements in Arkansas coal plants.

Commenters stated that Arkansas is an exporter of coal-fired energy, and hence has more coal 

capacity covered by the CPP than other states with the same consumption of coal-fired energy. 

Commenters stated that in 2012, Arkansas energy generation was 26% more than the sum of 
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Arkansas retail sales and 10% retail losses; in 2013, Arkansas generated at least 18% more 

energy than it used. Commenters stated that these large exports are partially due to the fact that 

30% of Arkansas coal capacity is owned by or sold under long-term contracts to out-of-state 

utilities. Commenters summarized that these non-Arkansas entitlements comprise the 

following: Independence 1 is 25% owned by Entergy Mississippi (According to its 2012 IRP, 

Entergy Arkansas sells another 4% of Independence 1 in long-term wholesale sales, most out of 

the state); Independence 2 is owned 25% by Entergy Mississippi, 7.1% by East Texas Coop, and 

14.4% by Entergy Power for sales into the wholesale market (According to its 2012 IRP, Entergy 

Arkansas sells about 8% of each White Bluff unit in long-term wholesale sales, most out of the 

state); Plum Point is 36% owned by out-of-state utilities; 57% is owned by LS Power, which 

sells another 38% to out-of-state utilities and 11% into the wholesale market. The remaining 

15% or so (about 100 MW) is owned by or sold to Empire District Electric, which has a peak 

load of about 1,150 MW and about 3.3% of its sales (or a peak of about 40 MW) in Arkansas (So 

even this capacity is mostly serving out-of-state load); Turk is owned 8% by Oklahoma 

Municipal Power Authority and 7% by East Texas Electric Coop, Inc; Meanwhile, SWEPCo has 

two coal units (Turk and Flint Creek) in Arkansas, for about a third of its coal capacity, even 

though Arkansas represents only about a fifth of SWEPCo's sales.

Commenters stated that the costs of reducing emissions from Arkansas's coal fleet will, and 

should, fall heavily on the out-of-state utilities with entitlements in Arkansas coal plants. 

Commenters stated that if the Arkansas DEQ allocates those plants' CO2 allowances equal to 

their share of total Arkansas coal-plant emissions, the out-of-state owners will need to pay other 

generation owners for emission credits or accept lower production levels. Commenters added 

that if the Arkansas DEQ allows unused allowances from other states to count towards Arkansas 

compliance, the owners may reduce output at out-of-state plants, or retire them entirely, to free 

up allowances to meet their Arkansas obligations. 

Commenters stated that partly as a result of coal generation for exports, a much greater 

percentage of Arkansas energy production is from coal than the national average. Commenters

added that in 2013, 53% of Arkansas electric energy production came from coal, more than a 

third greater than the 39% of national energy generation from coal (EIA Form 923, 2013). 

Commenters concluded that retirement of the exporting coal plants would reduce Arkansas's 

generation requirements. Commenters added that retiring the four Independence and White Bluff 

units would require replacing only about three of them with renewables, energy efficiency, and 

increased operation of gas combined-cycle units. Commenters stated that under a mass-based 

approach, as advocated by SWEPCo and the Bipartisan Policy Center presentations 

(October Presentations 1 and 2), these reduced exports would move Arkansas toward compliance 

with the Plan.

Comment 62: AR - generation companies targeted AR for recent installation of coal-fired 

plants; subsequently compliance in AR is made more difficult

Response 62: See sections V.C. and VIII of the final rule preamble of the CPP 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 asserted that generation companies targeted AR for recent installation of coal-fired 

plants; subsequently compliance in AR is made more difficult.

Commenters stated that while other states were announcing the retirement of coal capacity, 

generation companies were building coal plants in Arkansas; the 665 MW Plum Point was 

completed in 2010, and SWEPCo completed the 600-MW Turk plant in 2012. Commenters

added that since 2008, 96% of Arkansas capacity additions have been coal, compared to 15% in 

the rest of the U.S. Commenters stated that the two plants added in Arkansas, a plant with only 

about 1.5% of U.S energy output, amounted to over 8% of national coal-plant additions. 

Commenters stated that while SWEPCo was adding Turk to Arkansas's compliance burden, 

SWEPCo announced the retirement of its Welch 2 unit in Texas, and its affiliate Public Service 

of Oklahoma has announced retirement of both of its Northeastern coal units, which will make 

compliance in Texas and Oklahoma easier. Commenters stated that no coal capacity has been 

retired in Arkansas, and no retirements have been announced. Commenters asserted that 

nationally, about 230 coal-fired units totaling 22,000 MW were retired in 2005-2013, or about 

7% of total coal capacity. Commenters added that another 35,000 MW, roughly 11% of the fleet, 

are scheduled for retirement in 2014-2026, even before any effect of the Plan.

Comment 63: AR - Arkansas is behind in EE and RE, but should be able to meet goals

Response 63: See sections V.A., V.E., and VII 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 asserted that AR is behind in regards to energy-efficiency and renewables, but AR 

should be able to meet its goals.

Commenters stated that the Arkansas utilities have come late to energy-efficiency. Commenters

stated that until the Arkansas PSC ordered the investor-owned utilities to ramp up their efforts, 

starting in 2009 (Order, APSC Docket Nos. 06-004-R, 08-144-U), none of the Arkansas utilities 

had made any significant effort to improve customer efficiency. Commenters added that the 

Arkansas utilities have also been passive with respect to renewable resources, neither acquiring 

significant amounts of utility-scale renewables nor encouraging customers to add roof-top solar 

and other behind-the-meter renewables.

Commenters stated that the decisions of the utilities led to their current situation, and some 

additional effort may be required to catch up to the Northeast on energy-efficiency, neighboring 

states on renewables, or most states in replacing their coal fleets with cleaner generation. 

Commenters added Arkansas has some offsetting advantages, including the ramp-up of energyefficiency programs much earlier and faster than the EPA anticipated, the development of large 

amounts of wind capacity (and transmission to bring it to market) in adjacent states, a large 
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amount of underutilized natural-gas combined-cycle (NGCC) capacity, and falling costs for solar 

and wind resources.

Commenters concluded that while the state goals are derived from EPA's very conservative 

estimate of achievable reductions from each block, Arkansas should be able to exceed any of the 

three targets and meet its goals with multiple combinations of dispatch, renewables and 

efficiency. Commenters added that while SWEPCo was correct in observing that "EPA's 

building blocks are based on flawed assumptions," those flaws mostly understate the magnitude 

of resources for compliance.

Comment 64: AR - 82% is an achievable capacity factor for NGCCs; Arkansas can close cofired plants and re-dispatch if raise NGCC capacity factor

Response 64: See section V.D. of the final rule preamble of the CPP for the EPA’s response to 

this comment and more information about Building Block 2.

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

Commenters stated that AR can close coal plants and re-dispatch that energy if they raise the 

NGCC capacity factor to 78%; and added, 82% overall is an achievable capacity factor. 

Commenters stated that the coal plants that are most likely to be retired prior to 2030, White 

Bluff and Independence, with or without the CPP, produced about 20,950 GWh of energy in 

2013. Commenters stated that bringing the NGCC plants with the capacity factors of less than 

70% in 2013 up to 70% would produce about 17,800 GWh of additional energy; raising the 

NGCC capacity factors to about 78% would replace all the energy from Independence and White 

Bluff, without any renewables or load reductions. 

Commenters added that the EPA uses nameplate capacity for the NGCCs in computing the 

feasible capacity factors. Commenters stated that a unit's nameplate capacity is often greater than 

its summer or winter rated output, so a 70% capacity factor on nameplate capacity will require 

more than 70% capacity factor for the other ratings. Commenters stated that based on the 

summer ratings above (and a corrected 580 MW rating for Dell), the capacity factors equivalent 

to 70% of nameplate would be 77% to 84% and 82% overall for the various non-cogenerating 

units. Commenters added that these are readily achievable capacity factors for most NGCCs. 

Commenters stated that while the AECC asserts that "the actual tested ratings of NGCCs, and 

not the nameplate ratings, should be used to determine a state's NGCC capacity under the 

proposed Rule" (Clean Power Plan Comments, September 30, 2014, at 4), the requirements for 

Arkansas would be the same at an 82% capacity factor based on summer rating.

Comment 65: AR - Can exceed the EPA targets for renewables

Response 65: See section V.E. of the final rule preamble of the CPP for the EPA’s response to 

this comment and more information about Building Block 3.
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The following are summaries of the specific public comments under this comment:

Commenters stated AR can exceed EPA targets for renewable.

Commenters stated that the potential adds up to nearly thirteen times the EPA's renewableenergy target for 2030. Commenters concluded that while not all of this potential will be 

developed, Arkansas certainly can exceed the EPA targets with imports, indigenous renewables, 

or a combination of the two.

Comment 66: CA - Appears current mix of energy and environmental programs in California 

will achieve CPP goals

Response 66: Please see Section V, VI, and Section VIII of the preamble for discussion of 

changes to the BSER between proposal and final based on comments and our further 

consideration, the quantification of the BSER in this final rule, and a description of the state 

goals.

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

Commenters stated that the U.S. EPA set California's interim rate-based goal (the average of 

years 2020-2029) at 556 lbs CO2/MWh and the final goal at 537 lbs CO2/MWh by 2030. 

Commenters indicated that the California Energy Commission (CEC), in consultation with ARB 

and California Public Utilities Commission, performed a preliminary analysis to estimate the 

expected CO2 rates in 2020, 2024 and 2030. Commenters indicated that based on this analysis, 

they believe that using the current mix of energy and environmental programs being 

implemented within California will bring California into compliance with the U.S. EPA 

proposed targets for California. Commenters said in addition, U.S. EPA's rule, as proposed, will 

further support existing state policies on energy and air quality.

Comment 67: CA - CPP is less stringent than what California could achieve

Response 67: Please see Section V, VI, and Section VIII of the preamble for discussion of 

changes to the BSER between proposal and final based on comments and our further 

consideration, the quantification of the BSER in this final rule, and a description of the state 

goals.

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

Commenters asserted that the Clean Power Plan is less stringent than what CA could achieve.

Commenters asserted that California will very likely exceed its 33% RPS by 2020. Commenters

added that many expect that Gov. Brown will propose new targets for 2030 that will be 

equivalent to between 50% and 60% renewable energy standard.
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Commenters warned that while it is clear that the EPA intends to build upon California's 

progress, the EPA must take care to avoid watering down the efforts of California and its 

neighboring states.

Comment 68: CA - California's existing state-mandated 33 RPS is undervalued in the 2030 

target

Response 68: See section V.E. of the final rule preamble of the CPP for the EPA’s response to 

this comment and more information about Building Block 3.

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

Commenters stated that additional renewable energy resources identified in building block 3 of 

the proposal are based on a regional analysis of existing renewable portfolio standards (RPS). 

Commenters said that for the west, this means that California's existing state-mandated 33 

percent RPS is undervalued in U.S. EPA's 2030 target for California, as many other western 

states do not have comparably aggressive RPS goals. Commenters indicated that using the EPA's 

current methodology, California is credited with a 20 percent RPS goal by 2030 to meet the 

proposed target of 537 lbs CO2/MW-hr.

Comment 69: CO - Climate change impacts are obvious and costly. The EPA should finalize 

and enforce the CPP as quickly as possible

Response 69: See section I.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 argued climate change impacts are obvious and costly, without the CPP, the power 

mix will remain dominated by coal. Commenters urged EPA to finalize and enforce the CPP as 

quickly as possible.

Commenters stated at the direction of City Council, who serve as the Board of Directors for the 

utilities, an independent consultant conducted a study of various options for decommissioning 

the Martin Drake facility. Commenters stated the consultant issued their final report at the end of 

2013. Commenters stated the study estimated the net present value of the direct financial costs 

for all the utility's power generation over a 30-year time horizon for a dozen decommissioning 

scenarios. Commenters stated the costs were compared to a base case of continuing operation of

Martin Drake for 20 years. Commenters stated the study also estimated the net present value of 

the indirect social and environmental costs of the various decommissioning options over the 

same 30-year period. Commenters added there are many components to the indirect costs but 

greenhouse gas and critical air contaminants were the two largest.
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Commenters stated the study concluded, that given the age of Martin Drake, it is not feasible to 

continue to operate it for 20 more years. Commenters added it also determined that the indirect 

costs were nearly as large as the direct financial costs. Commenters stated two scenarios allowed 

for decommissioning in six and nine years adding natural gas or a mix of wind and natural gas 

generation. Commenters added these two scenarios increased direct costs by 4.8 to 5.4 percent 

while decreasing indirect costs by 14 to 19 percent, three to four times the direct cost increase. 

Commenters stated while these direct cost increases are not trivial, it must be realized that 

Colorado Springs Utilities prides itself on having electric rates 20 percent lower than the 

comparable utilities along the front range. Commenters stated hence, this aging coal plant could 

be decommissioned while still easily allowing the utility to maintain below average rates.

Commenters stated you would think that Colorado Springs' City Council, having just witnessed 

firsthand the trauma and destruction from two back to back wild land fires and seeing the results 

of this study would quickly move to create a decommissioning plan. Commenters added 

however, it's obvious from public comments that direct financial costs far outweigh the indirect 

social and environmental costs for a majority of accounts. Commenters stated executives in the 

utilities state they can keep Martin Drake operating for another 30 years.

Commenters stated Colorado Springs is just one of hundreds of communities across the country 

with similar scenarios playing out. Commenters stated climate change impacts are becoming 

obvious and very costly. Commenters added the cost to change the electric power generation mix 

is manageable, yet without these proposed greenhouse gas regulations, our power generation mix 

will remain dominated by coal because there's insufficient reasons to change. Commenters

concluded please proceed to finalize and enforce these regulations as quickly as possible.

Comment 70: CO - The EPA should require states to achieve the deepest reduction possible and 

use wildlife-friend renewables and energy efficiency. The EPA should strengthen Colorado's 

current goal

Response 70: The EPA has not included demand-side energy efficiency (building block 4) in the 

final BSER determination. See section V.E. of the final rule preamble of the CPP for the EPA’s

response to this comment and more information about Building Block 3 and see the CO2

Emission Performance Rate and Goal Computation TSD for CPP Final Rule supporting the final 

CPP.

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

Commenters requested that EPA work to ensure that it achieves the deepest reductions possible 

by requiring states to use wildlife friendly renewable energy and energy efficiency and not just 

by simply burning more natural gas. Commenters added that in its rulemaking EPA estimated 

that Colorado can generate nearly 15 percent of our power from renewable sources in 2020, 

which is substantially less ambitious than our own standards of our own energy goal of 30 

percent power from renewables in 2020. Commenters concluded that the EPA should strengthen 

the proposed standard to reflect Colorado's current goal.
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Comment 71: CO - The EPA should strengthen the proposed RE goal for Colorado

Response 71: See section V.E. of the final rule preamble of the CPP for the EPA’s response to 

this comment and more information about Building Block 3 and see the CO2 Emission 

Performance Rate and Goal Computation TSD for CPP Final Rule supporting the final CPP.

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

Commenters stated in its rulemaking EPA estimated Colorado can generate nearly 15% of our 

power from renewable sources in 2020 which is substantially less ambitious than our own 

statewide renewable energy goal of 30% power from renewables by 2020. Commenters

concluded the EPA should strengthen the proposed standard to reflect Colorado's current goal.

Comment 72: CO - RE targets are achievable; emission reduction targets must not be weakened

Response 72: See section V.E. of the final rule preamble of the CPP for the EPA’s response to 

this comment and more information about Building Block 3 and see the CO2 Emission 

Performance Rate and Goal Computation TSD for CPP Final Rule supporting the final CPP.

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

Commenters argued existing state policies indicate that the CPP's renewable energy targets are 

achievable. The commenters further argued that (for CO and other states) the emission reduction 

targets must not be weakened. 

Commenters stated the City of Aspen is a strong proponent of renewable energy, and as such 

supports EPA's assessment of the potential for renewable energy deployment in individual states 

and regions. Commenters added several independent analyses indicate that EPA's suggestions 

are achievable. Commenters stated for example, the renewable energy generation levels 

projected by the US Energy Information Administration (EIA) describe more renewable energy 

in 2020 under a business as usual approach than what the CPP's interim requirements (in 2020) 

suggest. Commenters added further, 29 states and the District of Columbia currently have 

renewable electricity standards (RESs). Commenters stated interestingly, the actual renewable 

energy generation of 7 states in 2013 exceeded the CPP's 2030 renewable energy target. 

Commenters stated additionally, 17 of those 29 states have smaller renewable energy targets 

under the CPP that what their RES's require under state law; several standouts include:

• California (State: 33% by 2020; EPA: 21% by 2030)

• Colorado (State: 30% by 2020; EPA: 21% by 2030)

• Connecticut (State: 27% by 2020; EPA: 9% by 2030)

• Hawaii (State: 40% by 2030; EPA: 10% by 2030)

• Massachusetts (State: 22% by 2020; EPA: 24% by 2030)
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• Minnesota (State: 31% by 2020; EPA: 15% by 2030)

• New York (State: 29% by 2015; EPA: 18% by 2030)

• Oregon (State: 25% by 2025; EPA: 21% by 2030)

Commenters concluded given the City of Aspen's positive experience with renewable energy 

diversification, the enormous benefits that RGGI states have experienced under their carbon 

abatement program, and the fact that many states already have mechanisms in place to meet or 

exceed the CPP's 2030 renewable energy suggestions, commenters stated that the CPP's 

emission reduction targets must not be weekend in the final rulemaking.

Commenters stated Tri-State claims they are already doing all they can, and that particularly 

expanded transmission would be required to install more renewable energy. Commenters said 

rights of way difficulties, timeframe for licensing, and risk in having to abandon too difficult 

transmission projects altogether are indeed daunting; yet Tri-State fails to consider multiple 

renewable energy opportunities on existing or soon to be built transmission lines. 

Comment 73: CO - Colorado is ahead of the curve, but should continue to advance renewables

Response 73: See section V.E. of the final rule preamble of the CPP for the EPA’s response to 

this comment and more information about Building Block 3 and see the CO2 Emission 

Performance Rate and Goal Computation TSD for CPP Final Rule supporting the final CPP.

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

Commenters stated that CO is ahead of the curve but should continue to advance renewables, be 

a national leader.

Commenters stated that now many of us know and applaud the fact that Colorado's already ahead 

of the curve and moving away from coal as a primary energy source and posturing the increase 

of renewable energy statewide from sources like wind and solar. Commenters added that just 

meeting minimum level of this newly proposed standard through past action should not be the

final goal. Commenters stated that to continue being a national leader for renewable energy and 

really tackling climate change before it's too late, Coloradans should be embracing the standard 

as a way to increase our state's efforts to reduce carbon pollution, to increase our new energy 

goals, and to help the neighboring states move forward quickly to make this national proposal a 

success across the American west where there is ample opportunity and resources to set an 

example for the nation.

Comment 74: CO - The EPA's approach for calculating state target levels of renewable energy 

performance is flawed. 
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Response 74: See section V.E. of the final rule preamble of the CPP for the EPA’s response to 

this comment and more information about Building Block 3 and see the CO2 Emission 

Performance Rate and Goal Computation TSD for CPP Final Rule supporting the final CPP.

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

Commenters stated EPA examined mandatory state RPS requirements from the Database for 

State Incentives for Renewables and Efficiency ("DSIRE"). The commenters said EPA 

essentially ignored the factors that distinguish RPS requirements by state, and further overlooked 

states' investment in EE, hydro, or qualified fossil fuels (waste coal, carbon capture 

sequestration). The commenters said EPA only considered the RPS requirements for investor 

owned utilities (IOUs) in calculating state effective levels in 2020; under this approach, 

Colorado's effective RPS level in 2020 is 30% (as compared to Colorado's existing RES 

requirement of 30% by 2020 for IOUs, and 10-20% by 2020 for municipalities and rural electric 

cooperatives). 

Commenters stated the Proposed Rule relies on resource projections that overestimate reasonably 

achievable expansion levels and exceed industry plans. The commenters said EPA assumes 

qualifying non-hydro renewable generation in the contiguous U.S. to grow from 213 TWh in 

2012 to 281 TWh by 2020, reaching 523 TWh by 2030. The commenters said these projections 

far exceed the Energy Information Administration ("EIA") non-hydro renewable generation 

forecast in their Annual Energy Outlook 2013 ("AEO 2013") that grows from 202 TWh in 2012 

to 275 TWh by 2020, reaching 317 TWh by 2030 for all sectors. The commenters said EPA 

assumed rapid growth in non-hydro renewable generation also exceeds its own long-term 

forecast in the Proposed Rule's regulatory impact assessment (356 TWh in 2030). 

Commenters stated in Colorado specifically, EPA assumes qualifying non-hydro renewable 

generation to grow from 6,193 GWh in 2012 to 7,426 GWh by 2020, reaching 10,840 GWh by 

2030; these projections far exceed EPA's own modeled results during its regulatory impact 

analysis which predict renewable expansion to reach 6,676 GWh by 2020 and 9,612 GWh by 

2030. The commenters said notably, Colorado's RES allows the contribution of small 

hydroelectric facilities (<30MW) towards compliance. The commenters said these facilities 

account for 1.73% of Colorado's total electric generation; excluding the contribution of these 

resources as EPA has done in its analysis would lower Colorado's 2020 effective RES level to 

28.27%. The commenters said EPA's implicit incorporation of hydroelectricity into the targets 

and subsequent exclusion of it as a renewable energy resource under the Proposed Rule sets too 

high of regional renewable targets than was previously established under the states' respective 

programs. The commenters said EPA also attempted to quantify regional inequalities, and in so 

doing, blurred the realities of any one state; this has the effect of distorting Colorado's 

investments in renewable energy, dating back at least to the passage of the RES, made effective 

by Colorado vote, in 2004. 

Commenters stated Colorado applies a multiplier to select, in-state resources; specifically, 

Colorado's RES allows every kWh generated from solar electric generation located in the 

territory of an IOU, cooperative or municipal utility, and generated by a facility that begins 

operation before July 1, 2015 to count as 1.5 kWh, and 3.0 kWh, respectively for RES 
114

compliance purposes. The commenters said EPA's inclusion of the multiplier in the calculation 

of an effective target makes EPA's target higher than what is realistically attainable for Colorado.

Comment 75: CO, NM, NV - Western states are prepared to meet the EPA's standards

Response 75: Please see Section V, VI, and Section VIII of the preamble for discussion of 

changes to the BSER between proposal and final based on comments and our further 

consideration, the quantification of the BSER in this final rule, and a description of the state 

goals.

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

Commenters asserted that western states have been proactive and are well prepared to meet 

EPA's standard within the timeframe EPA proposed.

Commenters stated that Western Resource Advocates has analyzed Colorado, New Mexico and

Nevada's current energy policies and finds that these three states will be very close to achieving 

EPA's proposed 2030 targets. Commenters added that in fact, in Colorado and New Mexico, 

policies already in place will accomplish over 80 percent of what EPA standard requires. 

Commenters added that in Nevada with existing policies and plans, the state and main utility will 

have little if anything else to do to meet EPA's proposed requirements, and that's summarized 

from the graph in front of me.

Commenters stated that in the west many states and utilities have already been taking the 

initiative to advance clean energy and prove energy efficiency and transition the most carbon 

intensive power plants to cleaner sources of energy; key stakeholders including our utilities, state 

agencies, health and environmental advocates have worked together to pursue creative, workable 

solutions. Commenters added that those solutions protect our community's air quality and health 

and have protected electricity customers from untenable rate increases.

Commenters stated that for example, Colorado's Clean Air Clean Jobs Act, Nevada's Senate Bill 

123, and New Mexico's recent plans to advance the retirement of a portion of San Juan 

generating station put these three states in an excellent position to meet the standards and are 

moving those states toward a lower carbon footprint. Commenters added that all five 

southwestern states in the four corners region have energy efficiency programs in place to further 

reduce the environmental impacts of our energy needs.

Commenters stated that an analysis finds that if Colorado and New Mexico simply follow 

through on what they're planning to do anyway under current policies, both states will 

accomplish over 80 percent of EPA's standard. Commenters added that in Nevada, by 

implementing current policies as already planned, the state will need to take few additional 

actions, if any, to meet EPA's standard.

Commenters concluded that while there's more to do over time and Colorado and New Mexico 

as well as several other states in the region; western stakeholders can and will come together to 
115

find workable low-cost practical solutions that protect communities, economies, jobs, and the

environment.

Comment 76: CO - CPP is achievable and beneficial

Response 76: Please see Section V, VI, and Section VIII of the preamble for discussion of 

changes to the BSER between proposal and final based on comments and our further 

consideration, the quantification of the BSER in this final rule, and a description of the state 

goals.

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

Commenters argued the CPP is achievable and beneficial.

Commenters stated based on the success of current carbon abatement and renewable energy 

programs, Aspen is confident that the CPP's nationally aggregated 30 percent CO2 reduction 

targets for 2030 are achievable and in fact quite modest. Commenters added further, analysis 

shows that because of early action and existing policy, Colorado is well positioned to meet the 

CPP's proposed target of 35 percent below 2005 levels by 2030.

Commenters stated a significant part of the City of Aspen's support for the proposed Rule comes 

from ongoing experience diversifying and de-carbonizing electricity sources. Commenters stated 

currently, Aspen Electric's generation portfolio contains approximately 80 percent renewables, 

yet it has the fifth lowest residential electricity rates (amongst municipal utilities) in the state. 

Commenters added rates are also lower than those of most Colorado coops and investor owned 

utilities. Commenters stated the Aspen region is also an energy efficiency success story. 

Commenters stated between 2011 and 2013, Energy Smart Colorado worked in Gunnison, Eagle 

and Pitkin Counties to improve energy efficiency in participating homes by an average of 10 

percent, while generating $2.25 in benefits for every $1 invested. Commenters stated clearly, 

investments in renewables and efficiency by former and current community leaders have not 

only benefitted the environment, they have also insulated ratepayers against the inherent 

volatilities of fossil-fuel markets and prices (prices that should only increase as their true costs to 

society begin to be monetized). Commenters added given that the Aspen area's renewable energy 

and energy efficiency penetration have surpassed the CPP's 2030 BSER calculation for Colorado 

(6.5 percent increase in renewable energy and a 6.7 percent decrease in electricity demand), the 

City of Aspen is confident that the Plan is achievable.

Commenters stated likewise, early and ongoing action at the state level makes Colorado wellpositioned to meet EPA's proposed standards. Commenters added under current policies 

including the state Renewable Energy Standard (RES), Colorado is projected to reduce emissions 

28 percent by 2030. Commenters stated this means that if the CPP is not strengthened, Colorado 

will meet 81 percent of the proposed rate reductions (needing only an additional 7 percent) to 

comply with the 2030 target under current state plans. Commenters stated Colorado's RES is 

projected to reduce CO2 emissions by 30 million tons, create more than 33,000 jobs and generate 

4.3 billion in economic output. Commenters added further, many Western residents and 

Coloradans are supportive of the CPP. Commenters expounded at the Denver hearings on the 
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CPP during the summer of 2014, supportive testimony outnumbered those opposed by 5 to 1. 

Commenters stated lastly, Larry Wolk, Executive Director and Chief Medical Officer at the 

Colorado Department of Public Health and Environment, submitted a letter to Administrator 

McCarthy with 15 state agency leaders in 2013 urging EPA to develop a "stringent but flexible" 

framework to reduce carbon pollution from the electricity sector. Commenters concluded the 

proposed CPP closely aligns with what these state officials requested in a national rule requiring 

carbon pollution standards for the electricity sector.

Commenters stated states that have already taken a regional approach to reducing carbon 

emissions have done so successfully and their experience indicates that the CPP is achievable. 

Commenters added the nine Northeast and Mid-Atlantic States that participate in the Regional 

Greenhouse Gas Initiative (RGGI) have reduced power plant GHG emissions by almost 40 

percent since 2005 while creating 23,000 job years, generating $2.4 billion in economic benefits, 

reducing electric rates by 8 percent, saving consumers in more than $2 billion in energy costs 

and generating $10.4 billion in health benefits. Commenters stated not only does RGGI's 

ongoing success demonstrate that reducing emissions can be an economic opportunity, it also 

emphasizes that a regional approach to emissions reduction, (which is allowed and encouraged in 

the proposed CPP) can bolster efficiency and achievability. Commenters added during the 

written comment period on this rulemaking, the RGGI states submitted a joint letter to EPA 

requesting that the CPP be strengthened.

Comment 77: CO - EE - EnergySmart Program details and accomplishments

Response 77: The EPA has not included demand-side energy efficiency (building block four) in 

the final BSER determination. See section V.A. of the final rule preamble of the CPP for the 

EPA’s response to this comment and more information about Building Block 4.

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

Commenters detailed the EnergySmart program and how EE improvements have been 

accomplished through the program.

Commenters stated in the last four years Boulder County has implemented and piloted 

innovative energy efficiency services that are now being adopted by both the Independent Power 

Provider and Municipal Utilities serving our county. Commenters stated the EnergySmart service 

uses assessments, advising and incentives to make energy efficiency upgrades easy and 

financially rewarding for homeowners, businesses and property owners. Commenters added in 

just four years, 13,000 homes and 3,200 (nearly one-half) of Boulder County businesses have 

participated in the service. Commenters stated residential participants have taken advantage of 

nearly $1.5 million in rebates and $2 million in loan financing. Commenters added on the 

commercial side, Boulder County businesses have already invested nearly $12 million in energy 

efficiency projects.

Commenters stated EnergySmart introduced the personalized assistance of an energy advisor to 

our community, which has proven successful. Commenters stated through EnergySmart rebates, 
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customers implement efficiency upgrades that utility DSM offerings alone have been unable to 

motivate.

Commenters stated a Department of Energy BetterBuildings grant, funded through the American 

Reinvestment and Recovery Act, launched EnergySmart, and funded additional EnergySmart 

rebates that when combined with existing utility rebates brought the payback period within the 

customer's horizon. Commenters added on average, EnergySmart rebates made up 25 percent of 

the total rebate required to move the project. Commenters stated of the 1,177 commercial 

projects completed since EnergySmart began, more than half are now accruing savings for the 

customer beyond what it cost to implement the project.

Commenters stated each year since EnergySmart's inception, the demand for both advising and 

rebates has exceeded capacity. Commenters stated other entities have adopted offerings modeled 

on EnergySmart innovations, including the City of Longmont's Business Efficiency Grant and 

Platte River Power Authority and Xcel Energy's Refrigeration and HVAC Efficiency programs. 

Commenters stated hundreds of contractors have begun specializing in efficient equipment, and 

energy service companies such as McKinstry have begun working with local property owners at 

scale.

Commenters stated with EnergySmart's initial projects now yielding savings, customers have 

appetite for further upgrades, and property owners are coming to view upgrades as a standard 

investment, whether motivated by competition, cost savings, code requirements, or tenant 

relations. Commenters stated building owners who relied heavily on EnergySmart advisor 

assistance early on are incorporating efficiency upgrades and maintenance into their business 

models and undertaking projects on their own. Commenters added this frees EnergySmart to 

pursue new customers, deeper energy retrofits, and clean energy supply.

Comment 78: CO - BB1 HRI

Response 78: See section V.C. of the final rule preamble of the CPP for the EPA’s response to 

this comment and more information about Building Block 1.

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

Commenters stated that some stakeholders are stating that the EPA's 6% assumption of 

improvement is over-stated, and merely 1.5% is achievable. The commenters stated it is 

interesting to note that, in 2006, Tri-State's most recently constructed coal fired power plant - (a 

portion of) Springerville in Arizona - was built as a sub-critical plant than others built in that 

period, all being super-critical. The commenters said significant improvements are possible.

Comment 79: CO - Building blocks irretrievably flawed; cannot ramp up to 70% capacity

Response 79: See section V.D. of the final rule preamble of the CPP for the EPA’s response to 

this comment and more information about Building Block 2.
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The following are summaries of the specific public comments under this comment:

Commenters argued EPA failed to support the claim that the states' targets under each Building 

Block are achievable.

Commenters stated with the exception of Building Block 1, each of the measures that EPA has 

proposed to adopt as part of the BSER for existing affected EGUs reaches beyond the individual 

regulated sources themselves, and therefore is not a "system of emission reduction" under section 

111 of the Act. Commenters added nonetheless, even if the Agency's proposed BSER were 

lawful, EPA's Proposal is faulty because the Agency has failed to support its claim that the states' 

targets under each Building Block are achievable.

Commenters stated it is fundamental that a standard of performance under section Ill must 

"reflect[] the degree of emission limitation achievable through the application of the best system 

of emission reduction which (taking into account the cost of achieving such reduction and any 

non-air quality health and environmental impact and energy requirements) the Administrator 

determines has been adequately demonstrated." Commenters added EPA may not base its 

determination that a standard is achievable on "mere speculation or conjecture." Commenters

stated rather, the Agency bears the burden of showing that a standard is achievable "for the 

industry as a whole" and "under the range of relevant conditions which may affect the emissions 

to be regulated," including "under most adverse conditions which can reasonably be expected to 

recur." Commenters stated in order to show that the Proposal is achievable, EPA must "(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 concluded EPA has not done so in this rulemaking. Commenters added rather, the 

Agency has set targets under each Building Block that far exceed what is feasible or costeffective. Commenters stated in particular, the targets under Building Blocks 1 and 2 (i.e., the 

Building Blocks that involve measures taken by affected EGUs, either individually or 

collectively across a state) are not supported by the rulemaking docket and are simply not 

achievable. Commenters added Building Block 3 is based on unrealistic assumptions, and 

Building Block 4 gives rise to enforcement difficulties. Commenters concluded as a result, 

compliance with the state goals will be extremely costly and difficult (if not impossible) for any 

state as a whole and will certainly be impossible for many individual affected EGUs to achieve. 

70% Capacity not achievable. Commenters stated EPA proposes to find that it is achievable for 

each state, in the aggregate, to shift generation from coal-fired units to NGCC units until the 

existing NGCC units reach a statewide maximum capacity factor of 70 percent based on 

nameplate capacity (or 65 percent, under the alternative goals on which EPA solicits comment). 

Commenters stated in developing this target and concluding that it is achievable, EPA adopts an 

overly simplistic view of how electricity is generated, dispatched, and distributed by utilities in 

the real world. Commenters added the Agency incorrectly assumes that all NGCC units have 

roughly the same ability to ramp up generation; that all NGCC units have access to adequate 

natural gas; that load formerly served by coal generation can instead be served by in-state NGCC 

generation; and that new pipeline and transmission infrastructure can be built quickly and 

inexpensively. Commenters stated yet electricity is not the easily-produced, uniform, fluid 
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commodity that EPA assumes it is. Commenters concluded many significant barriers will 

prohibit a state's NGCC units from ramping up generation to an overall 70 percent capacity 

factor, making this Building Block unachievable. 

70% Capacity not achievable; NGCC's not subject. Commenters stated for the two NGCC 

facilities that Tri-State owns, ramping up utilization to a 70 percent annual capacity factor would 

be impossible. Commenters stated Tri-State owns the J.M. Shafer Generating Station (J.M. 

Shafer) and the Rifle Generating Station (Rifle), both located in Colorado. Commenters stated as 

an initial matter, Tri-State notes that neither of these NGCC plants should be subject to the 

Proposal, as neither plant meets the applicability criteria for the source category that EPA 

defined in its January 2014 proposed NSPS for new EGUs. Commenters stated as proposed, the 

source category would include a stationary combustion turbine only if it actually supplies "onethird or more of its potential electric output and more than 219,000 MWh net-electrical output to 

a utility distribution system on a 3-year rolling average basis." Commenters stated according to 

the 2012 generating data on which EPA relies in this Proposal, J.M. Shafer operated at only a 21 

percent capacity factor, while Rifle operated at a mere 3 percent capacity factor and generated 

less than 19,000 MWh. Commenters added the 3-year rolling average net-electrical output for 

each of these generators is well below 219,000 MWh. Commenters concluded thus, because 

these units do not fall within the source category defined in the January 2014 NSPS proposed 

rule for new EGUs, section 111(d) would not authorize Colorado to impose any federally 

enforceable obligation on Tri-State's NGCC units.

Shafer and Rifle baseload facilities. Commenters stated it is extremely uncertain whether J.M. 

Shafer and Rifle could even operate at a higher capacity factor. Commenters added both of those 

plants were built for reliability purposes (i.e., they operate only at times of high electricity 

demand) and not as baseload facilities. Commenters concluded if the plants had to run at a higher 

capacity factor, it is likely those plants would quickly have technical issues and fail.

Permits prohibit from reaching 70% CF. Commenters stated in any event, even if Tri-State's 

NGCC units were subject to the Proposal (which they are not), the limits contained in their Title 

V permits would prohibit them from increasing utilization to a 70 percent annual capacity factor. 

Commenters stated these permits contain numerous requirements, including annual fuel usage 

limitations. Commenters added J.M. Shafer's annual natural gas consumption is limited to 10,375 

million standard cubic feet per year (for the turbines), while Rifle's consumption is limited to just 

1,650 million standard cubic feet per year.

Commenters stated there are numerous scenarios in which the facilities could operate during a 

year and reach these annual fuel limits. Commenters stated the actual duration of operations that 

would be required to reach the limit - and consequently, the maximum permitted annual capacity 

factor for each unit - will vary depending on a number of different variables, including ambient 

temperature, operating load, the number of startups during a year, the duration of operation 

following a startup, and the duration of downtime between a shutdown and the next startup.

Incorrect nameplate capacities. Commenters added in addition, if Tri-State's NGCC units were 

subject to the Proposal, EPA utilized incorrect nameplate capacities for some of the units at 
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Rifle. Commenters stated the incorrect nameplate capacities were reported on 2012 EIA Form 

860. Commenters stated Tri-State is currently working with the Department of Energy to make 

these necessary corrections to the correct nameplate capacities.

Commenters stated Tri-State has about a half dozen gas generators that are or can be converted 

to combined-cycle for greater efficiency. The commenters said today these generators have only 

single digit capacity factors, being operated a tiny percentage of the time. The commenters said 

industry argues that the 70% capacity factor is unattainable. The commenters said this could be a 

valid concern; and suggest EPA bring on board not only NREL, but also university engineering 

departments and even some industry consulting firms to assess the engineering feasibility of 

combining greater levels of renewables with natural gas, since improving wind and solar 

capacity factors will reduce the percentage of time that natural gas power plants must firm up 

these resources.

Comment 80: CO - Rule doesn't account for different business models thus increasing costs and 

causing confusion

Response 80: For the EPA’s response to this comment, see the Regulatory Impact Analysis for 

the Clean Power Plan Final Rule.

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

Commenters stated the rule does not account for different business models, thus increasing costs 

and causing regulatory confusion. 

Commenters stated that Colorado's electric utility sector is not uniform in its ability to raise 

capital to build new infrastructure or recover costs of implementing regulation. Commenters

noted that in addition, no single regulatory authority has jurisdiction over all utilities; Electric 

utilities in Colorado follow several models:

Commenters stated investor-owned utilities that are owned and capitalized by shareholders and 

are guaranteed a rate of return on investment subject to rate regulation by the Public Utilities 

Commission Rural electric cooperatives that are owned by their members who carry the cost of 

providing the power distributed to the membership and are regulated by the members Generation 

and transmission cooperatives that generate and sell power and transmission services to its 

member cooperatives, and are governed by a board of its members and Municipal utilities that 

generate and buy power and transmit the power to citizens within their jurisdiction and are 

governed by boards of elected officials. Commenters stated that the differing methods of 

providing capital and absorbing costs of changes in utility services is not recognized or reflected 

in the proposed rule, or in the "building blocks" which are offered by EPA as means of achieving 

compliance with the rule.

Comment 81: CO - concerned about wide variances in required emissions reduction by state
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Response 81: For the EPA’s response to this comment, see the CO2 Emission Performance Rate 

and Goal Computation TSD for CPP Final Rule supporting the final CPP.

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

Commenters argued the wide variance in states emission reductions is problematic.

Commenters stated Holy Cross is concerned by the wide variances in the required emission 

reductions by state, which might be mitigated in a few key ways. Commenters added for 

example, create for calculation purposes a Block 5 that retires power plants that have been in 

commercial operation for a certain number of years (e.g., 55-60 years) and that have carbon 

intensity per MWH above a certain threshold. Commenters stated EPA has stated that the states 

do not have to use all of the blocks; however, this additional block may close some of the wide 

variances between states. Commenters added also, it may be appropriate to place an upper and 

lower collar on required state emissions reductions, such as a maximum reduction of 35% and a 

minimum reduction of 25%.

Comment 82: CO - The EPA should use 2013 data for Pueblo Airport Generating Station 

(PAGS)

Response 82: See Appendix 1 to the CO2 Emission Performance Rate and Goal Computation 

TSD for CPP Final Rule for the unit-level 2012 data used in the final CPP rule. The Pueblo 

Airport Generating Station in Colorado was identified as commencing operation in 2012 and 

based on comments, the EPA is treating units that commenced operation part way through 2012 

as under construction and estimating generation and emissions of a capacity factor assumption of 

55% for NGCC units. 

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

Commenters asserted that EPA should use 2013 data for the Pueblo Airport Generating Station 

(Colorado).

Commenters stated that for Pueblo Airport Generating Station (PAGS): The 2012 data year used 

by EPA results in inaccuracies due to 2012 being a partial 40CFR75 Acid Rain Program 

reporting year for CO2. Commenters stated that the PAGS facility was initially commissioned in 

late 2011. Commenters stated that the 40CFR75 reporting for CO2 emissions begins 180 days 

after "commercial operation." Commenters stated that thus, for the six PAGS combustion 

turbines the CO2 reporting began around the April 2012 timeframe. Commenters concluded that 

this partial year of CO2 data, along with the complete year of generation data, severely distorts 

the PAGS emission rate calculations. Commenters suggested using the 2013 data as a 

replacement for the 2012 data. Commenters concluded that utilizing any calendar year other than 

2013 would necessitate reliance on estimates. 

Comment 83: DE - Delaware has met goals already and should be exempt from the CPP.
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Response 83: The EPA does not agree that Delaware should be exempt from the CPP. Please see 

the CO2 Emission Performance Rate and Goal Computation TSD for CPP Final Rule supporting 

the final CPP for final goals.

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

Commenters stated that the EPA plan has numerous flaws. The commenters stated that the 

overall goal is to reduce CO2 emissions 30% by 2030 from 2005 levels. The commenters argued 

that Delaware should be exempted from the plan (as VT and DC have already been exempted) 

because Delaware reduced emissions 29% by 2012, and 40% by 2013. With the correct data, the 

commenters stated that Delaware will better the EPA emission rates by 4% without changing 

capacity factors between various generation sources. Because Delaware exceeded the EPA 

emission goals without adopting the Clean Power Plan, the commenters asserted that Delaware 

should be exempted from the plan.

Comment 84: DE – Affected Units

Response 84: The EPA agrees and has added Garrison Energy Center to the baseline inventory 

of likely affected units as shown in Appendix 1 to the EPA’s CO2 Emission Performance Rate 

and Goal Computation TSD for CPP Final Rule

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

Commenters recommended EPA add Calpine's Garrison Energy 300 MW NGCC as an existing 

affected unit.

Commenters stated that EPA utilized the NEEDS v5.13 data base (p. 6 Goal Computation TSD) 

for units under construction. Commenters stated that this data base did not include Calpine's 

Garrison Energy 300 MW NGCC that is being constructed in Delaware. Commenters added that 

this unit commenced construction before January 8, 2014 and has an anticipated start-up date in 

mid-2015.

Comment 85: FL - Cape Canaveral NGCC should be categorized as "under construction 

NGCC"

Response 85: The EPA agrees and has categorized Cape Canaveral NGCC as under construction 

as discussed in section VI of the final rule preamble of the CPP and shown in the Appendix 1:

unit-level data file to the CO2 Emission Performance Rate and Goal Computation TSD

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

Commenters indicated the Cape Canaveral NGCC plant was mis-categorized in the EPA 

analysis.
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Commenters indicated that the EPA's eGRID dataset classifies FPL's Cape Canaveral NGCC 

plant in the existing NGCC category. According to commenters, the EPA's Goal Computation 

TSD stated, however, that "NGCC capacity that was not operating in 2012" should be classified 

as 'under construction NGCC.' Commenters noted that the EPA's eGRID data for the Cape 

Canaveral NGCC shows that this unit did not send any power to the grid in 2012; therefore, this 

unit should be categorized as an "under construction NGCC" unit for goal setting purposes. 

Commenters stated that when a NGCC unit is listed as an "under construction NGCC" unit, the 

EPA's goal setting methodology states that the NEEDS database is used to determine that unit's 

capacity. Therefore, commenters stated, Florida's existing NGCC capacity should be reduced by 

1,295 MW (nameplate capacity of Cape Canaveral) and Florida's under construction NGCC 

capacity should be increased by the capacity of Cape Canaveral according to the NEEDS 

database.

Comment 86: FL - Clarification for Florida's under construction NGCC - Port Everglades

Response 86: The EPA did review its list of under construction units considered likely affected 

sources. It relied on comment data, publically reported EIA data (including 2013), and NEEDS. 

It noticed the 2013 reported status of “T” for the Port Everglades NGCC facility which is 

described as “regulatory approval received. Not under construction...” The EPA has not 

included it in its final rule inventory of likely affected units, but notes that this does not 

constitute an applicability determination of the unit.

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

Commenters noted that the NEEDS database does not identify specific "Under Construction 

NGCC" units in Florida. Commenters asserted that the listed 1,157 MW of "Under Construction 

NGCC" capacity represents the summer capacity of FPL's Riviera NGCC facility. Commenters

said that if this is the case, it appears the EPA has not included the under construction capacity 

from FPL's Port Everglades NGCC. Commenters asserted this unit commenced construction 

prior to January 8, 2014 and therefore should be classified as an "Under Construction NGCC." 

Commenters concluded that if this is accurate, Florida's "Under Construction NGCC" capacity 

should be increased by the capacity of Port Everglades according to the NEEDS database.

Comment 87: FL - Tallahassee's Arvah B. Hopkins Unit 2 capacity must be corrected

Response 87: The EPA has switched its assessment of NGCC generation to relying on the 

summer capacity metric as described in section V.A of the final rule preamble of the CPP. The 

summer capacity rating for this unit is listed as 140 MW, consistent with the commenters’

statement.

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

Commenters indicated that the capacity of one of the units in eGRID is incorrect.

Commenters said that the City of Tallahassee's Arvah B. Hopkins Unit 2 is characterized in the 

2012 eGRID database as having a nameplate capacity of 259.2 MW. Commenters stated that this 
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unit's true capacity is, however, significantly lower. According to Commenters, Unit 2 was 

originally a 230 MW (summer net rating) gas/oil steam EGU. Commenters stated that the steam 

unit was repowered for use as a heat recovery boiler and as a result of the reduced heat input, 

now has a summer net rating of 140 MW. Commenters indicated that the facility is physically 

unable to generate 259.2 MW; therefore, its potential generation capacity should be identified as

140 MW.

Comment 88: FL - Comments on the IPM modeling results; the EPA should use net-summer 

capabilities

Response 88: The EPA is using net summertime capacity rather than nameplate capacity for 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 argued that EPA should use net-summer capabilities for baseline calculations.

Commenters stated (regarding the IPM modeling results) it appears EPA has used nameplate 

capacity for all generating units to calculate the state emission target. Commenters added EPA 

should have used unit net-summer capabilities as reported by all generators to NERC, FRCC, 

and EIA. Commenters concluded this approach would capture the summer peak generation 

capability and is the more appropriate baseline.

Comment 89: FL - FPL plans to continue to operate four 800 MW oil-fired units at Manatee 

and Martin generating facilities

Response 89: See section VIII.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:

Commenters argued that FPL plans to continue to operate four 800 MW oil-fired units at 

Manatee and Martin generating facilities. 

Commenters stated EPA's modeled projection is that FPL's Manatee and Martin oil-fired 

generating facilities will retire. Commenters added these four 800 MW units provide reliable fuel 

diversity to the cast and west coasts of our service territory in the event FPL loses natural gas 

supply. Commenters concluded it is important that FPL maintain the fuel diversity option 

provided by continued operation of these oil-fired units and FPL plans to continue to operate 

these units.
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Comment 90: FL - Fuel diversity is important to Florida

Response 90: See section VIII.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:

Commenters argued the importance of fuel diversity in Florida.

Commenters stated fuel diversity in Florida and nationally cannot be stressed enough, and its 

importance is great enough to warrant prior regulation at the federal level (see discussion above 

regarding the Fuel Use Act). Commenters added fuel diversity has served the United States well 

through frequent periods of fuel supply limitations, many of them related to natural gas 

disruptions (e.g., hurricanes Katrina and Rita) resulting in little impact to electric grid reliability. 

Commenters stated the extreme cold of January and February 2014, particularly in the MidAtlantic and Northeast states provided a peek into the potential consequences of reducing fuel 

diversity and over-concentrating EGU demand into natural gas. Commenters stated with many 

EGUs eliminating their ability to utilize fuel oil in order to comply with environmental 

regulations, these units instead relied solely on natural gas whose spot prices reached record 

levels exceeding $100/mmBtu. Commenters stated as EPA's proposal results in additional 

migration from coal to gas as a fuel choice, cost will become a secondary problem when EGUs 

are faced with gas supply shortages and reliability is jeopardized.

Commenters stated this fuel diversity need is especially critical for Florida given its geographic 

location, lack of native energy production capacity and limited electric transmission import 

capability. Commenters stated with the exception of a limited amount of electricity that can be 

transported into the state, Florida is essentially an island that relies on generating units within the 

state and the necessary fuel supply for those units. Commenters stated Florida's current electric 

reliability is dependent on EGUs' ability to import fuel supply for either immediate consumption, 

or to store it for consumption later. Commenters stated coal is a storable fuel source in Florida 

while natural gas is not. Commenters added Florida does not have the geological formations to 

economically store a material amount of natural gas underground. Commenters stated EPA's 

proposal must allow for a substantial amount of coal-fired electric generation to remain in 

Florida to ensure some level of fuel diversity and the resulting reliability benefits. Commenters

concluded to remove more than 90 percent of coal capacity from Florida as proposed by EPA 

would obligate Florida to rely solely on 'just in time' inventory for nearly all of its fuel supply, 

with reliability consequences for any disruptions in the supply chain.

Comment 91: FL - RE

Response 91: The EPA has revised its block three quantification based on comment. See 

sections V.A. and V.E. of the final rule preamble of the CPP for more information about 

Building Block 3 and see the CO2 Emission Performance Rate and Goal Computation TSD for 

CPP Final Rule supporting the final CPP.
126

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

Commenters stated Seminole works to maintain a balanced and diversified generation portfolio 

that includes SGS and MGS, as well as capacity and energy provided through short-, medium-, 

and long-term purchased power agreements ("PPAs") with other utilities, independent power 

producers, and government entities. The commenters said these resources reflect a mix of 

technologies and fuel types, including one of the state's largest renewable energy portfolios, 

although Seminole sells a portion of the renewable energy credits ("RECs") associated with its 

renewable generation to third parties, which can use the RECs to meet mandatory or voluntary 

renewable requirements. The commenters said the specific amount of generation Seminole 

purchases from PPAs varies year to year, but on average, PPAs account for around 40 percent of 

the total demand. The commenters said the balance and diversity in Seminole's generation and 

PPA mix reduces exposure to changing market conditions, helping keep rates competitive; fuel 

diversity is also of paramount importance for Seminole and Florida due to its unique geographic 

location and already-heavy reliance on out-of-state natural gas supplies. The commenters said 

Seminole has had a specific policy in place for years to acquire additional renewable resources, 

either through ownership or PPAs; specifically, Seminole's Board Policy No. 308 expresses its 

commitment to develop and utilize renewable energy resources, particularly where costeffective; this has resulted in Seminole entering into numerous PPAs for renewable generation; 

accordingly, the reasonably available and cost-effective renewable options in Florida are already 

being utilized, and EPA's assumption that Florida can do substantially more is erroneous. 

Commenters stated that it appeared "that EPA has not taken into account requirements under 

PURPA and Florida law regarding the purchase of renewable energy by Florida utilities." 

Commenters asserted "that federal and Florida law, along with the technical feasibility of 

renewables in Florida (not in North Carolina or the region), should determine the extent of

renewable generation that could be developed and used to offset emissions from fossil sources." 

Furthermore, commenters urged "EPA to remove the six percent at risk nuclear from the 

calculation of Florida's performance requirements" because it is based on a generic, non-Florida 

assumption and because it creates a more stringent performance requirement and decreases 

compliance flexibility.

Comment 92: FL - Transmission capability in Florida is not unrestrained

Response 92: See section V.D. of the final rule preamble of the CPP for the EPA’s response to 

this comment and more information about Building Block 2.

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

Commenters said that the EPA's IPM modeling accounts for transmission limitations between 

NERC regions. Commenters said that this modeling assumes, however, that transmission 
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capability within each NERC region is unrestrained (i.e., there are no technological or logistical 

barriers preventing the movement of electricity within the region). Commenters posed the 

question that given Florida's unique peninsular geography, has the EPA considered whether this 

assumption unrealistically assumes that Florida's transmission capabilities are adequate to meet 

the modeled assumptions of 70% dispatch.

Comment 93: FL - The EPA must properly consider Florida's transmission and natural gas 

supply issues

Response 93: See section V.D. of the final rule preamble of the CPP for the EPA’s response to 

this comment and more information about Building Block 2.

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

Commenters argued EPA must properly consider Florida's transmission and natural gas supply 

issues.

Commenters stated EPA's existing-source proposal creates greater fuel supply challenges by 

eliminating over 90 percent of the existing coal facilities in Florida. Commenters stated although 

EPA's proposal assumes adequate natural gas supply is available to all utilities in order to 

support the contemplated increase in gas fired electric generation, this assumption, specifically, 

does not account for fuel supply risks associated with the production, processing, storage and 

transportation of natural gas supply to power plants in peninsular Florida.

Commenters stated unlike solid fuel (coal) and liquid fuel (oil), natural gas is not easily stored 

due to its physical characteristics that require significantly more volume per unit of energy 

stored. Commenters added natural gas storage facilities must also possess specific characteristics 

to safely and economically store a material amount of fuel for use during periods of supply 

disruption.

Commenters stated all of the natural gas consumed by EGUs in Florida is produced outside the 

state and imported via one of the interstate gas pipelines. Commenters added historically, the 

vast majority of the gas supply transported into Florida was produced along the gulf coast 

(Alabama, Mississippi, Louisiana, Texas) from shallow and deep-water offshore platforms. 

Commenters stated offshore natural gas production has declined in recent years and onshore, 

unconventional gas production is making up an increasingly large percentage of the supply 

transported into Florida. Commenters stated this supply originates from production regions even 

further away from the state (Oklahoma, Arkansas, north Louisiana, and south Texas) and is 

dependent on multiple interstate pipelines in order to reach Florida. Commenters stated Florida's 

increased reliance on the "upstream" pipeline network creates a new form of risk for the state 

that is not addressed by EPA's proposal and one that would be exacerbated with the removal of 

coal and oil-fired generation and the associated storable nature of their respective fuels within the 

state.

Commenters stated currently, Seminole holds enough firm gas transportation capacity to dispatch 

its existing owned and tolled (purchased power) NGCC facilities at a 70 percent capacity factor 
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but this will reduce Seminole's available gas transportation capacity for use in simple cycle gas 

facilities during periods of peak demand. Commenters added however, should Seminole be 

responsible for constructing NGCC generation capacity to replace its coal-fired facilities and 

operate those at a 70 percent capacity factor, Seminole will need a minimum of 150,000 

decatherms per day ("Dths/day") of incremental firm gas transportation capacity to meet this 

need.

Commenters stated to put that into perspective, the Gulfstream Natural Gas System pipeline is 

fully subscribed and the Florida Gas Transmission ("FGT") pipeline has varying volumes of 

unsubscribed capacity posted on its website as of July 22, 2014. Commenters stated these range 

from 88,500 Dths/day in summer 2014 to 184,000 Dths/day during the 2017-2021 period. 

Commenters stated beginning November 1, 2021, and beyond, FGT has 214,000 Dths/day of 

unsubscribed capacity. Commenters stated if other utilities are forced to take similar actions, 

there will be insufficient gas transportation capacity available into the state of Florida to support 

the required NGCC generation. Commenters added if a third pipeline is constructed, which 

Seminole understands is required to meet Florida's gas needs regardless of EPA's existing-source 

proposal, that third pipeline will need to be expanded beyond its currently contemplated size to 

support this incremental gas demand from NGCC facilities. Commenters stated NERC has also 

expressed concern with EPA's proposal and its lack of consideration of pipeline capacity 

restraints.

Commenters stated EPA must provide ample time for EGUs to negotiate contracts for the 

requisite gas supply and transportation capacity and for the permitting and construction of the 

necessary pipeline infrastructure. Commenters emphasized contracting decisions made with the 

urgency to comply with EPA's proposed timelines may not be the optimal decisions for 

consumers in the long-term. Commenters concluded gas transportation commitments will likely 

have a 20-year minimum time horizon meaning that the next generation will continue to pay for 

the cost of hasty decisions.

Comment 94: FL - The EPA should correct errors related to Florida's goals, recalculate goals, 

and provide an opportunity for public review/comments on revised goals

Response 94: For the EPA’s response to this comment, see the CO2 Emission Performance Rate 

and Goal Computation TSD for CPP Final Rule supporting the final CPP.

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

Commenters argued EPA should correct errors related to Florida's goals, recalculate, and provide 

opportunity for public review/comments.

Commenters stated EPA made numerous factual and technical errors in its calculation of 

Florida's goals. Commenters added when just correcting for the first two errors (changing the 

nameplate MW to net, and the average emission rate to the actual rate), Florida's proposed goal 

in 2030 is well over 900 lb/MWh. Commenters stated EPA's other mistakes are equally 

erroneous, and must be addressed as well. Commenters concluded accordingly, EPA must 
129

correct all of the errors related to Florida's goals, recalculate the goals, and provide an 

opportunity for public review and comment.

Comment 95: FL - Revised calculation for Florida goal

Response 95: For the EPA’s response to this comment, see the CO2 Emission Performance Rate 

and Goal Computation TSD for CPP Final Rule supporting the final CPP.

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

Commenters provided a revised calculation for the Florida goal. 

Commenters stated that taking the suggestions and recommended corrections described in the 

above sections, the City has presented a revised calculation of the state goal, consistent with the 

more appropriate, yet still challenging, updates to building blocks 2, 3, and 4. Commenters added 

that these calculations are designed to provide a sense of how the issues identified in the City's 

comments impact the potential goals.

Commenters concluded that based on the revised calculations using the corrected noted in these 

comments, the Florida final goal would be no lower than 1,068 lb/MWh. Commenters added that 

it should be noted that this calculation is conservative in that it does not revise all steps just those 

with specific insights. Commenters stated that for example, the calculation does not adjust 

building block 1 and many other inputs.

Comment 96: FL - CHP units should not be included in Florida's goal calculation

Response 96: In the final CPP, all emissions from likely affected CHP plants are included in the 

baseline, please see the CO2 Emission Performance Rate and Goal Computation TSD for CPP 

Final Rule supporting the final CPP.

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

Commenters argued that combined heat and power (CHP) units cannot re-dispatch to higher 

capacity factors in the same way that non-CHP units can. The commenters argued that EPA's 

assumption to re-dispatch to 70 percent is unreasonable, and CHP units should not be included in 

Florida's goal calculation.

Commenters stated EPA improperly included combined heat and power ("CHP") units in its 

Building Block 2 goal calculation, mistakenly assuming that CHP units can redispatch to higher 

capacity factors in the same manner that non-CHP NGCC units can. Commenters stated this is in 

error, as CHP dispatch largely depends on the needs of adjacent facilities, not the needs of the 

grid. Commenters concluded EPA's assumption that CHP units can redispatch to 70 percent is 

unreasonable, and CHP units should not be included in Florida's goal calculation. Commenters

added EPA must recalculate Florida's goal excluding all CHP units from the calculation. 
130

Commenters stated if, however, EPA chooses to include CHP units in Florida's goal calculation, 

it must do so according to the same applicability criteria that EPA establishes under the new 

source rule. Commenters added as is discussed below, EPA's new- and existing-source proposals 

provide different applicability criteria for CHP units.

Comment 97: FL - The EPA should calculate Florida's goal using 2005 data

Response 97: See section VI.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:

Commenters recommended EPA revise the FL goal using 2005 data

Commenters stated that while the City is not recommending a specific goal, they are 

recommending that EPA revise the Florida state goal using 2005 data which aligns with the 

President's baseline, and allows for credit for efficiency improvements, re-dispatching, increases 

in renewable energy, and demand side management already implemented.

Comment 98: FL - Florida shouldn't be penalized for early carbon reductions; 2020 goal is not 

achievable

Response 98: In the final rule, the EPA has moved the start date of the interim period from 2020 

to 2022. See sections I.A., VI.D., VIII.B, and VIII.C. 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 argued Florida shouldn't be penalized for early carbon reductions and the 2020 goal 

is unachievable.

Commenters stated the EPA rule aims at reducing Florida's carbon emissions 38 percent from 

2012 to 2030, with an interim emission reduction goal of 27 percent starting in 2020. 

Commenters stated unfortunately, the proposed rule gives no credit for Florida's 20 percent 

carbon reduction since 2005, while simultaneously increasing generation by 12 percent. 

Commenters stated the City strongly believes that this important achievement should be counted, 

and not effectively penalize the state for early reductions. Commenters added in addition, to 

allow sufficient time for states to develop their programs and then for utilities to develop plans 

for compliance, additional time beyond the year 2020 is needed. Commenters concluded the 

2030 goal is optimistic, but 2020 goal is not achievable and certainly EPA has not demonstrated 

that the utilities in Florida could make changes sufficient to reach the goal.
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Comment 99: FL - The goal for Florida is not fair. Florida should be given credit for customerowned renewables. 

Response 99: For the EPA’s response to this comment, see the CO2 Emission Performance Rate 

and Goal Computation TSD for CPP Final Rule supporting the final CPP. EPA has regionalized 

building block two meaning that the reduction potential from incremental NGCC in Florida are 

observed regionally instead of concentrated in Florida steam sources. This may address some of 

the concern addressed in the coment below regarding equity, state goal level, and % reduction.

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

Commenters stated that the EPA's goals for Florida are not equitable. Commenters expounded 

that the 2030 goal for Florida is 740 lb/MWh, which is more than a 56 percent carbon dioxide 

("CO2") reduction from 2005 levels. Commenters added that however, the CPP's 2030 goal for 

the nation is "30 percent from 2005 levels.'' Commenters stated that the EPA has not provided 

justification for Florida's goal to be significantly higher than the national average. Commenters

added that it also is telling that the EPA's goals for Florida's existing fossil fuel generation are 

more stringent than the CO2 goals recently established as Best Available Control Technology in 

the EPA's "Standards of Performance for Greenhouse Gas Emissions from New Stationary 

Sources: Electric Utility Generating Units" (79 FR 1429). Commenters concluded that should not 

be possible under the Clean Air Act. 

Commenters stated that Florida also should be given credit for customer-owned renewable 

generation that is subsidized through net metering rates, tax exemptions, or rebates from the 

State or the local utility. Commenters added that Florida and its ratepayers are directly and 

indirectly subsidizing these customer-owned low emission generators, and the EPA's goal should 

give Florida credit for its achievements.

Comment 100: FL - Florida's goal is unachievable

Response 100: For the EPA’s response to this comment, see the CO2 Emission Performance 

Rate and Goal Computation TSD for CPP Final Rule supporting the final CPP.

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

Commenters argued EPA's method for determining the RE goal for Florida is flawed and the 

goal is unachievable. 

Commenters stated the renewable energy generation goal that EPA has calculated for Florida is 

unachievable. Commenters stated EPA's methodology for determining the goal is fatally flawed 

because it arbitrarily ties a state's goal to the RPS goals of other nearby states. Commenters

stated the goals of these states reflect each state's highly unique renewable energy potential 

which often may not actually require as much renewable energy generation as the state goals 

purport. Commenters stated as a result, the state renewable energy generation targets, including 

that for Florida, are unreasonably aggressive and do not take into account factors affecting the 

actual renewable energy growth potential in each state. Commenters added EPA's own IPM 
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modeling results indicate that predicted renewable energy generation by the end of the 

compliance period is not economical to meet the renewable energy targets EPA used in its goal 

calculation. Commenters urged EPA to withdraw the proposed state goals and reduce its 

renewable energy generation targets based on a state evaluation of renewable energy potential.

Commenters were greatly concerned with the methodology EPA used to set the BSER and the 

resulting Florida performance requirements for existing electric generating units (EGUs). 

Commenters said, as previously noted, EPA's assumptions and analysis supporting its Proposed 

Rule, and the Florida CO2 pounds per megawatt-hour (lbs./MWh) emission performance 

requirements presume an implementation strategy that either bypasses or preempts the FPSC's 

exclusive jurisdiction under Chapters 366 and 403, Florida Statutes. Commenters said, the EPA's 

Proposed Rule establishes CO2 lbs./MWh emission performance requirements using national or 

regional averages rather than assessing what is reasonable and technically achievable in Florida. 

Commenters said, moreover, EPA did not consider Florida-specific policies in developing the 

Proposed Rule. 

Comment 101: FL - goals too aggressive

Response 101: The EPA has not included demand-side energy efficiency (building block four) 

in the final BSER determination. The EPA has changed the start date for the interim period from 

2020 to 2022. For the EPA’s response to this comment, see the CO2 Emission Performance Rate 

and Goal Computation TSD for CPP Final Rule supporting the final CPP.

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

Commenters stated that EPA's compliance BB 4 assumes that demand side management can 

reduce electric demand by 10% by 2030. The commenters stated that Florida continues to 

experience significant population growth that is not taken into account for the state or localities. 

The commenters stated that this rule subjects states with high economic or population growth to 

negative disparate treatment. In addition, the commenters stated that Florida utilities have had 

robust energy efficiency programs for many years. The commenters noted, according to EIA, in 

2012 Florida had one of the lowest annual per capita energy consumption rates in the country at 

210 million BTUs as compared to the national average of 302 million BTUs. The commenters

stated that there is no recognition of this in the rule, leading to the concern that this rule is based 

on a "one size fits all" approach, which is at odds with the flexibility intended to be provided to 

the states by the CAA statute in Section 111(d). 

The commenters stated that, overall, the four BB targets are far too aggressive for the allotted 

compliance period; the "glide path" is in actuality a cliff under the 2020-2022 requirements for 

many states; it leads to premature retirement of plants, stranded investment, and reliability 

issues; the costs to consumers of forced retirements are far too high; and the reductions are 

inappropriately front-loaded. The commenters stated that a much longer, smoother glide path is 

required and the interim targets should be eliminated entirely.

The commenters stated that the ESPS is based on specific statewide emission rate goals 

(mandatory) that EPA has determined are feasible for each state, where the greater a state's 
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ability to reduce CO2 emissions, the more stringent are its state emission reduction goals. The 

commenters noted that only BB 1 is an "inside the fence" control option.

The commenters stated that BB 1 and 2 reductions are "front loaded" and are effective in 2020. 

The commenters stated that to comply with the proposed mandatory emission goals, Florida must 

reduce CO2 emission by 31% from 2012 levels by 2020 and 40% by 2030, so that 75% of the 

compliance goal for Florida is front loaded to 2020. The commenters stated that to achieve this 

reduction EPA estimates that 90.72% of Florida's coal-fired generation would be re-dispatched to 

NGCC units. However, the commenters stated that coal-fired EGUs cannot run at such low 

capacity factors (e.g., 10%), so it is likely 100% of Florida's coal-fired EGUs will shut down. 

The commenters stated that front loading of BB 1 and 2 creates the majority of the cost impact of 

the ESPS due to stranded costs caused by premature coal unit shutdowns. The commenters stated 

that if the implementation date for the rule would be delayed sufficiently to avoid premature 

retirement of Florida's coal-fired EGUs, ESPS costs could be reduced by approximately 60% 

based on EPA cost factors in the proposed rule's RIA.

Comment 102: GA - The EPA must clarify the process to adjust for Plant Washington (GA) if 

necessary

Response 102: For the EPA’s response to this comment, see the CO2 Emission Performance 

Rate and Goal Computation TSD for CPP Final Rule supporting the final CPP. EPA did not 

consider Plant Washington a likely affected unit under 111(d) in its quantification of BSER.

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

Commenters stated that EPA should clarify in the final rule a process for adjusting the baseline 

emissions levels as well as the interim and final CO2 emission goals for Georgia in the event that 

Plant Washington is constructed and determined to be an existing source.

Commenters stated that Plant Washington is an 850 MW coal fired EGU proposed to be built in 

Washington County, Georgia. Commenters stated that the project currently has a valid PSD 

permit issued by Georgia EPD; a final determination on the NSPS regulatory status of Plant 

Washington has not yet been made. Commenters stated that If Plant Washington is constructed 

and in fact determined to be an existing source, emissions would have to be included in the 

baseline and goal calculations for Georgia.

Comment 103: GA - Inequity between the states; GA is penalized for early action

Response 103: See sections VI.D., VIII.B, and VIII.C. 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:
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Commenters argued that states are not treated equitably under the proposed rule, and that the rule 

penalizes states that took early action.

Commenters said that with the rules as currently drafted, Georgia is mandated with a 48% 

reduction in its carbon emission intensity rate, which is well above the 30% average required 

emissions reduction across all states. Commenters indicated that they understand that the EPA 

attempted to tailor the rules for individual states and not set a uniform reduction across all states. 

However, commenters indicated that Georgia is being asked to invest more heavily than almost 

every other state despite the massive emission reductions that have been achieved over the last 

decade and the projected emissions improvements from the addition of new nuclear power 

generation, increased deployment of renewables, and continued energy efficiency programs. 

Commenters concluded that the proposed rule is punitive toward states that have, on their own, 

proactively pursued emission reductions. 

Commenters stated while the Proposal's stated objective is to reduce emissions of CO2, the 

generation projections for Plant Vogtle - which emits no CO2 - have been used to justify more 

stringent CO2 standards for Georgia. The commenters said Oglethorpe Power's investment in 

Plant Vogtle will ultimately reach around $4-5 billion, an investment in reduced carbon 

emissions that the Proposal simply ignores. The commenters said instead, the lower goal set for 

Georgia will require more investment than other Southeastern states that do not have new nuclear 

capacity; the additional costs of achieving that lower goal will have to be passed along to our 

members.

Comment 104: GA - Georgia target is more stringent than most other states; too little credit is 

given for proactive management

Response 104: See sections VI.D., VIII.B, and VIII.C. 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 Chamber is concerned that there is too little credit given for the 

proactive management of and investment in the state's energy sector that has occurred in recent 

years and that the CO2 emissions reduction targets allocated to Georgia will impose an unfair 

burden on consumers, businesses and industry in this state. Commenters added that these targets 

are far more stringent than the goals EPA has proposed for most other states and are even more 

stringent than EPA's proposed 1,000 lb/MWh CO2 performance standards for new fossil-fuelfired power plants.

Comment 105: GA - All of Georgia's existing nuclear units are expected to be operational 

through the compliance period

Response 105: See preamble section V.A for a response.
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The following are summaries of the specific public comments under this comment:

Commenters stated that all of Georgia's existing nuclear units are expected to be operational 

throughout the compliance period of the exposed rule. Commenters also clarified that based on 

EPA's calculation methodology, Georgia's at-risk nuclear should be estimated as: (4082MW) 

(8760hrs) (90% capacity factor) (6%) = 1,930,949 MWH or 220.4 MW at-risk nuclear capacity, 

less than EPA's estimate of 237 MW.

Comment 106: GA – Under Construction Nuclear

Response 106: 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 stated EPA's treatment of Georgia's "under construction" nuclear, Vogtle units 3&4, 

is inequitable and misguided and would almost certainly result in higher electricity rates for our 

Members.

Comment 107: GA - Georgia is well positioned to use RE (solar) and EE to meet the proposed 

standard

Response 107: See section V.E. of the final rule preamble of the CPP for the EPA’s response to 

this comment and more information about Building Block 3 and see section V.A. of the final rule 

preamble of the CPP for the EPA’s response to this comment and more information about 

Building Block 4.

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

Commenters argued Georgia well positioned to use RE and EE to meet the proposed standard. 

The commenters discussed solar power potential and in particular how Georgia's recent solar 

projects were well below avoided cost.

Commenters stated Georgia is well positioned to use RE and EE in its plan to meet the proposed 

standard. Commenters added in particular, recent developments in the solar market demonstrate 

both the potential and cost-effectiveness of solar power as a compliance strategy.

Solar Energy. Commenters stated with the addition of 91 MW, installed solar capacity more than 

quadrupled in 2013, making Georgia the fastest growing solar market in the nation according to 

the Solar Energy Industries Association. Commenters added rapid growth will continue. 

Commenters stated under its Advanced Solar Initiative (ASI), Georgia Power Company has 

already contracted for an additional 58 MW of distributed generation (1 MW or less) to be online 

in 2014 and 566 MW of utility scale projects (greater than 1 MW) to be online in 2014-2016. 

Commenters stated another 100 MW of distributed generation is programmed under ASI for 
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2015 and 2016, and Georgia Power will build 30 MW projects on each of three army bases. 

Commenters stated Green Power EMC, which is owned by electric cooperatives, has a 20 MW 

project underway. Commenters concluded all in all, Georgia already has on the ground or in the 

pipeline at least 925 MW of solar capacity to be online from 2013 to 2016.

Commenters stated the potential for solar power is shown not only by the completed and 

scheduled projects, but also by the projects that were offered but not selected in the ASI process 

in 2014. Commenters stated a lottery was used to select the 58 MW of distributed generation. 

Commenters stated in that process, 976 projects totaling 784 MW were not selected. 

Commenters added a request for proposals (RFP) was used to select utility-scale projects. 

Commenters stated fifty-six third-party bidders offered 146 unique projects totaling 5,150 MW. 

Commenters stated in total, about 5.4 GW of distributed generation and utility-scale solar was 

offered for development but left on the table in 2014.

Commenters stated the cost-effectiveness of solar power in Georgia is demonstrated by the bids 

offered under the ASI RFPs for utility-scale solar. Commenters stated the first RFP procured 50 

MW at an average price of less than 8.5 cents/kWh. Commenters added Georgia Power 

announced that this price was below the utility's avoided cost. Commenters stated given this 

initial success in acquiring cost-effective solar energy, the next RFP was for all remaining utility 

scale solar in the ASI program, with a not to exceed price of 8.5 cents, resulting in the 

procurement of 516 MW at an average cost of less than 6.5 cents/kWh, well below avoided cost. 

Commenters concluded it is now clear that utilities in Georgia can acquire solar power for less 

than it costs to run their existing plants.

Commenters stated if the extra 5.4 GW of solar power offered in 2014 were developed over the 

next 15 years and Plant Vogtle units three and four come online as anticipated, Georgia could 

exceed the renewable energy generation projected for the state in Building Block 3. Commenters

stated the calculation projects 12,230,636 MWh of renewable energy by 2030, of which 27 

percent (3,278,536 MWh) was already in place in 2012. Commenters stated the 925 MW of solar 

capacity programmed since 2012, plus 250 MW of wind power from Oklahoma procured by 

Georgia Power, can be expected to provide another 17 percent. Commenters stated assuming a 

capacity factor of only 15 percent, adding 5.4 GW of solar generation would more than cover the 

remaining 56 percent, even without any more wind power or other renewables in the mix. 

Commenters concluded these numbers demonstrate that the level of RE projected by EPA under 

Building Block 3 is well within reach in Georgia.

Energy Efficiency. Commenters stated similarly, Georgia is well positioned on Building Block 4. 

Commenters stated Southface agrees that well-established practices for utility-based EE 

programs can cost-effectively be scaled to produce annual savings equal to 1.5 percent of sales. 

Commenters added Georgia is already further along that path than reflected in the calculations in 

Building Block 4. Commenters stated Georgia Power, which accounts for about 60 percent of 

retail sales in the state, has built a portfolio of EE programs that is currently saving 0.4 percent. 

Commenters stated the cost of energy saved at that level is only 1 cent/kWh. Commenters stated 

Georgia Power's experience establishes a solid foundation from which to expand utility-based 

EE as a compliance strategy. Commenters added furthermore, Georgia has a strong and 

expanding private marketplace for EE. Commenters encouraged a final rule that supports an 

"everything-should-count" approach to clean energy.
137

Comment 108: GA - Georgia has untapped potential for renewable energy production (solar)

Response 108: See section V.E. of the final rule preamble of the CPP for the EPA’s response to 

this comment and more information about Building Block 3.

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

Commenters stated GA has untapped potential for renewable energy production.

Commenters stated that while we have finally moved beyond the myth that solar energy doesn't 

work in Georgia and developed a strong solar market, we can do much, much more. Commenters

added that Southface maintains an online solar energy map that tracks solar installations across 

the state; we know of more than 920 residential and commercial projects with the collective 

capacity of 110 megawatts. 

Commenters stated that our utilities have also shown leadership in this arena. Commenters

expounded that Georgia Power's Advanced Solar Initiative will bring online more than 700 

additional megawatts of solar energy by the end of 2016. Commenters added that GreenPower 

EMC, which provides clean energy to the state's electric membership cooperatives, recently 

announced a 20 megawatt solar deal.

Comment 109: GA-Solar

Response 109: See section V.E. of the final rule preamble of the CPP for the EPA’s response to 

this comment and more information about Building Block 3.

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

Commenters stated Georgia is ready to deploy its solar energy resources. Commenters added that 

Solar is clean, carefully regulated, cost-effective, quickly deployed, and a proven resource.

Comment 110: GA - Solar energy is a cost-effective and abundant source of energy supply in 

Georgia. The EPA should not weaken Georgia's goal

Response 110: See section V.E. of the final rule preamble of the CPP for the EPA’s response to 

this comment and more information about Building Block 3.

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

Commenters stated that under a series of programs authorized by the Georgia Public Service 

Commission ("GaPSC"), Georgia Power has contracted for almost a gigawatt of electricity to be 

provided by solar resources. Commenters added that in 2011, the fully-integrated and regulated 

utility was ordered to procure 50 MW of solar through the large scale solar program. 
138

Commenters stated that a year later, Georgia Power requested - and the GaPSC ordered the 

Company - to procure 210 MW of solar capacity to be fully installed by 2016 as part of a 

program known as the Advanced Solar Initiative ("ASI"). Commenters added that building on 

the ASI and as part of the 2013 Integrated Resource Plan for Georgia Power, the GaPSC ordered 

an expansion of an additional 525 MW of solar (the expansion is known as "ASI Prime"). 

Commenters added that more recently, the GaPSC approved 90 megawatts of solar on army 

bases on October 23, 2014. 

Commenters stated that all of these projects have added cost-effective solar resources into 

Georgia Power's portfolio. Commenters added that Georgia Power was able to contract for 425 

MW - the entire amount allotted for utility scale under the ASI-Prime - at or below avoided 

costs. Commenters stated that under the latest offering for the ASI and the ASI-Prime, the 

pricing for chosen projects had an average cost of less than 6.5 cents per KWh. Commenters

added that the 90 MW to be installed at army bases will also fall below projected avoided costs. 

Commenters concluded that this means that none of these projects will increase rates.

Commenters stated that additional proposed projects and information continue to show that solar 

energy is a cost-effective and abundant source of energy supply in Georgia. Commenters stated 

that the National Renewable Energy Laboratory currently estimates over 3,100 GW of technical 

solar potential in the state. Commenters added that though a small portion of that technical 

potential, the same offering for the ASI and ASI Prime discussed above returned a significant 

number of projects: over 5.1 GW of proposed projects, which included 140 different offerings. 

Commenters added that although the exact pricing submitted is protected, one can assume most -

if not all - of these bids were at or below avoided cost, as bidding developers were made aware 

of this requirement. Commenters stated that as discussed above, only 10 percent of the proposed 

projects have been selected for purchase by Georgia Power. Commenters added that on 

November 6, 2014, building on the success of the 90 megawatts of solar to be installed on army 

bases, Georgia Power announced a similar deal with the naval base at Kings Landing.

Commenters stated that among the benefits cited for the project, the Company found that the 

naval project would "provid[e] an economical supply of electric power for the Company's 

customers." 

Commenters concluded that as Georgia has significant opportunity to expand cost-effective solar 

resources, the EPA should not weaken Georgia's targeted goal as proposed.

Comment 111: GA - Wind energy can save ratepayers money; the EPA should not weaken 

Georgia's goal

Response 111: See section V.E. of the final rule preamble of the CPP for the EPA’s response to 

this comment and more information about Building Block 3.

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

Commenters stated that in addition to taking a leadership position on solar, Georgia has recently 

taken steps embracing wind energy. Commenters added that in 2013, Georgia Power announced 

that it had signed two power-purchase agreements totaling 250 megawatts of wind power from 
139

Oklahoma. Commenters stated that under these deals - which were unanimously approved by the 

GaPSC (Georgia Public Service Commission) in 2014 - wind energy will begin flowing into 

Georgia in 2016.

Commenters stated that although this project will benefit the environment and will have the 

effect of reducing carbon emissions, it also provided a direct economic benefit to ratepayers. 

Commenters added that in fact, Georgia Power and Commission Staff found that the wind deals 

provided an "extraordinary advantage to ratepayers" at prices below avoided cost, which puts 

downward pressure on rates. Commenters concluded that this means that it was cheaper to 

purchase the wind resources and let some of the other units in Georgia Power's system - likely 

fossil units - sit idle. 

Commenters stated that there is substantial opportunity to invest in additional wind resources 

going forward - and likely at even lower prices. Commenters added that Commission Staff's 

testimony found that there was potential for other wind procurements from the midwest under 

existing infrastructure, and that Georgia Power was paying a premium for certain aspects of the 

contracts they had already signed. Commenters stated that there are at least two proposed high 

voltage direct current lines that, once constructed, will bring between 5 GW and 6.5 GW of wind 

energy to the southeast from the midwest and Texas. Commenters concluded that if Georgia 

utilities act proactively to purchase additional wind resources, they will be able to purchase a 

significant amount of wind energy - and help ratepayers save money.

Commenters concluded that as wind energy can also be added to the portfolio in a manner that 

can save ratepayers money, it is a cost effective resource for compliance with the Clean Power 

Plan, and the EPA should not weaken its proposed goal for Georgia.

Comment 112: GA - Georgia has anemic appliance efficiency programs, but good building 

codes and thermal efficiency programs; the EPA should take a look at the Energy Star Program

Response 112: The EPA appreciates the comments regarding energy efficiency programs and 

Energy Star, however the promulgated rule does not include a building block four as part of the 

BSER. Please see section V.A. of the preamble for more information regarding the building 

block four and demand side energy efficiency.

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

Commenters stated that the State of Georgia has had problems under the IRP; it has quite anemic 

appliance efficiency programs. Commenters stated that on the other hand, this state does have 

pretty good building codes, and thermal efficiency programs run by Georgia Power offer good 

value for dollar. 

Commenters stated the Federal Government can help by continuing DOE rulemaking on 

appliances and lighting. Commenters added EPA needs to take a look at the Energy Star 

program; the Energy Star program is used in Georgia as sort of the label that triggers the 

incentive program. Commenters added that the Energy Star program is not always up to date and 
140

there need to be more resources devoted to that. Commenters concluded that all sides of the 

argument should agree.

Comment 113: GA - There is significant opportunity to expand energy efficiency in Georgia

Response 113: See section V.A. of the final rule preamble of the CPP for the EPA’s response to 

this comment and more information about Building Block 4. See section VIII of the preamble 

for a discussion of alternative compliance measures and demand-side energy efficiency.

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

Commenters stated that there is significant opportunity to expand energy efficiency resources in 

Georgia. Commenters added that in 2005, the Georgia Environmental Finance Authority 

procured a study that showed that Georgia had the potential to save 29 percent of retail sales by 

2024. Commenters stated that under the aggressive scenario that it modeled, GEFA found that 

Georgia could have cost effectively saved approximately 8.7 percent of retail sales - which 

corresponded to a reduction of 12,546,554 MWh or 1.6GW of peak demand - by 2010. 

Commenters stated that although "[r]ealizing this potential would produce immediate dollar 

savings for customers, reductions in power plant emissions and substantial gains for the Georgia 

economy in the form of increased employment and personal income," much of this cost-effective 

energy efficiency potential is yet to be developed. 

Commenters stated that this is even though utility planning has shown how inexpensive energy 

efficiency measures are in Georgia. Commenters added that for example, one portfolio proposed 

by Georgia Power in 2013 illustrated the cost effectiveness of measures to save energy: the cost 

to save one kilowatt hour (KWh) for residential measures was 4 cents, and for commercial 

measures was 1 cent; although no industrial programs were proposed by Georgia Power for 

certification, costs to save one KWh for industrial measures under a separate scenario were 2 

cents per kwh. Commenters stated that the levelized costs of the approved programs equaled 1 

cent per kwh saved. 

Commenters concluded that as there is significant amount of cost-effective energy efficiency 

potential still to be developed in Georgia, the EPA should not weaken the targets that it has 

proposed.

Comment 114: HI - If the EPA revises goals, the EPA should address oil-fired units in 

establishing BSER for revised standards and the scope of the rule, and should provide a new 

comment period

Response 114: The EPA is not including emission performance goals for Hawaii in this final 

rule. See section VII.F. of the preamble for discussion of this issue.

The following are summaries of the specific public comments under this comment:
141

Commenters stated that we accept GHG emission rate goals as they are currently proposed for 

Hawaii; however, if EPA decides to significantly revise these goals, we would like oil fired units 

addressed in establishing BSER for the revised standards. Commenters stated that a large amount 

of the national fuel oil usage for energy generation is in Hawaii. Commenters added that 

unfortunately, for building block 1, EPA only addressed GHG abatement measures specific to 

coal fired units. Commenters stated that considering that a majority of the energy generation by 

affected EGUs in this state is from burning oil, heat rate improvements identified for oil fired 

units would be more representative in supporting BSER for Hawaii's EGUs. 

Commenters added that if the emissions rate goals in the proposed CPP are revised significantly, 

we would also like the EPA to update the proposed Plan with the new proposed standards and 

provide a new comment period.

Commenters stated that for Hawaii, CO2 emissions from 111(d) affected sources comprise 

approximately 67% of the CO2 emissions from all power plants. According to the commenters, 

the same ratio for the U.S. mainland is approximately 93%. The commenters respectfully 

requested that if EPA changes the scope of this rule, such that this percentage materially 

changes, then the commenters requested the opportunity to comment on the technical, economic 

and other impacts of this change on Hawaii.

Comment 115: HI - The combustion turbine at Kapaia Power Station is not an affected EGU

Response 115: The EPA is not including emission performance goals for Hawaii in this final 

rule. See section VII.F. of the preamble for discussion of this issue. It agrees that Kapaia Power 

Station would not be a likely affected EGU under 111(d).

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

Commenters stated they would like EPA to remove Kauai Island Utility Cooperative's Kapaia 

Power Station from the list of facilities subject to the performance goals in 40 CFR Part 60 

Subpart UUUU. Commenters noted that the combustion turbine that is listed as an affected EGU 

at this facility does not meet the criteria in 40 CFR Section 60.5795(b)(2) for the defined source 

category. Commenters stated that according to 40 CFR Section 60.5795(b)(2), in order for a 

stationary combustion turbine to be an affected EGU, the unit must burn 90% natural gas on a 

heat input basis on a 3-year rolling average. Commenters stated that the combustion turbine at 

Kapaia Power Station is permitted to burn naphtha, fuel oil No. 2, jet-A, heavy straight run 

gasoline, ethanol, and biodiesel. Commenters added that the combustion turbine at this facility is 

not permitted to burn natural gas or synthetic natural gas. Commenters concluded that therefore, 

the combustion turbine at Kapaia Power Station is not an affected EGU.

Comment 116: HI - The EPA should revise Hawaii's goal based on removing Kapaia Power 

Station's combustion turbine from affected EGUs, and should use more representative fuel data
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Response 116: The EPA is not including emission performance goals for Hawaii in this final 

rule. See section VII.F. of the preamble for discussion of this issue. See response 115.

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

Commenters stated that we examined the US Energy Information Administration data that EPA 

used to develop the Hawaii's emission rate goals presented in Table 1 of 40 CFR Part 60, Subpart 

UUUU. Commenters stated that this review identified a number of instances where Hawaii's 

emissions inventory information contained data specific to Hawaii fuels that was different from 

the fuel data used by EPA. Commenters stated that for Hawaii's review, emission rate goals were 

recalculated after removing Kapaia Power Station's combustion turbine from the list of affected 

EGUs, and substituting the more representative fuel data specific to Hawaii sources. 

Commenters added that as an example, the "2030 and thereafter" goal calculated by EPA was 

1,306 lb/MWhr versus 1,329 lb/MWh as calculated by Hawaii reviewers. Commenters stated 

that while the recalculated goal values were not significantly different from those determined by 

EPA, we request that EPA use the revised values if EPA decides to recalculate Hawaii's emission 

rate goals after the public comment period. Commenters included a comparison between EPA 

and Hawaii determined parameters and goal calculation results.

Comment 117: Commenters included Hawaii's 2012 Plant-Level Data for Likely Covered Fossil 

Sources.

Comment 118: Commenters included Hawaii's Unit level inventory

Comment 119: Commenters included awaii's re-calculations of state goals.

Comment 120: Commenters included Hawaii's heating value data and calculations for affected 

facilities.

Comment 121: Commenter s included Hawaii's DOH 2012 Emissions Inventory fuel quantity 

and heat content for facilities and fuels used in EPA-HQ-OAR-2013-0602-0256 data file.

Comment 122: Commenters included Hawaii's CO2 emission calculations: DOH Calculation 

uses facility reported annual average heating values (per 2012 Emissions Inventory Reports to

DOH) and EPA Fuel Emission Factors (kg/MMBTU) to calculate CO2 emissions

Comment 123: HI - fuel burning-throughputs

Commenters provided Hawaii's Fuel Burning-Throughput calculations for AES.

Commenters provided Hawaii's calculations for fuel burning-throughput for Honolulu facility.

Commenters provided Hawaii's corrections to fuel burning-throughputs for Hamakua facility.

Commenters provided Hawaii's corrections to fuel burning-throughputs for HC&S facility.
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Commenters provided Hawaii's corrections to fuel burning-throughputs for HPOWER1 facility.

Commenters provided Hawaii's corrections to fuel burning-throughputs for HPOWER2 facility.

Commenters provided Hawaii's corrections to fuel burning-throughputs for Kahe facility.

Commenters provided Hawaii's corrections to fuel burning-throughputs for Kalaeloa facility.

Commenters provided Hawaii's corrections to fuel burning-throughputs for Kapaia PS facility.

Commenters provided Hawaii's corrections to fuel burning-throughputs for Keahole facility.

Commenters provided Hawaii's corrections to fuel burning-throughputs for Maalaea facility.

Commenters provided Hawaii's corrections to fuel burning-throughputs for Puna facility.

Commenters provided Hawaii's corrections to fuel burning-throughputs for Waiau facility.

Commenters provided Hawaii's corrections to fuel burning-throughputs for Allen-Fuel facility.

Comment 124: HI - Description of worksheet

Response 117-124: The EPA appreciates the Hawaii corrections and information files provided, 

please see the CO2 Emission Performance Rate and Goal Computation TSD for CPP Final Rule 

supporting the final CPP for the final goals. The EPA is not including emission performance 

goals for Hawaii in this final rule. See section VII.F. of the preamble for discussion of this issue.

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

Commenters provided Hawaii's description of worksheet: Comparison of 2012 Hawaii EIA923 

fuel usage and heating data with that derived from CAB Emissions Inventory Reports: fuel set 

includes all available EIA923 and CAB data.

Commenters provided Hawaii's description of worksheet: 0256 Plant Level Data.

Commenters provided Hawaii's review of EPA 111(d) data presented in the EPA-HQ-OAR2013-0602-0256.xls" document and related documents identified in the EPA & EIA Documents 

sheet. Commenters stated that annual fuel usage, fuel heat content, and carbon dioxide emissions 

were evaluated based on 2012 Hawaii Department of Health Emissions Inventory data and EPA 

greenhouse gas emission factors. Commenters added that based on this review, the following 

recommendations/comments to EPA 111(d) data are presented. Commenters concluded that 

references, calculation details and discussion are presented in supporting pages.

Commenters provided Hawaii’s corrections to the Net Electric Generation calculations.

Comment 125: ID - Calculation of ID goal; hydropower; baseline; RE target setting method
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Response 125: See section VI of the final rule preamble of the CPP for a response to the concern 

about 2012 data representativeness for states with a large hydro portfolio. The EPA has made 

adjustments to the baseline reflecting to reflect generation in a non-outlier year for hydro 

generation.

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

Commenters stated the EPA's approach to the Proposed Rule of selecting a single year (2012) for 

establishing a baseline is inaccurate and fails to represent Idaho's electricity and emission mix; 

the single baseline year fails to capture the hydroelectric variability or accurately represent 

NGCC generation in Idaho. The commenters said using baseline years of 2010, 2011, or 2012 (or 

a combination of the three) does not resolve the problem because those years do not represent 

Idaho's current generation mix, and they will fail to produce a state performance goal that can be 

achieved at a reasonable cost. The commenters said the EPA must account for this discrepancy 

by allowing for hydroelectric normalization and re-formulating Idaho's goal with 70% NGCC 

capacity factors for the baseline. 

Commenters stated hydropower generation is variable and must be normalized; the EPA's 

proposed rule unfairly places Idaho (and other states with significant hydropower resources) at 

significant risk of non-compliance and increased cost due to weather-induced hydropower 

generation variability. The commenters said this variability effects the amount of emissions in 

the baseline used to determine the EPA's goal. The commenters said in order to eliminate the 

effect of hydro generation variability on the ability of states like Idaho to comply with the 

Proposed Rule, the EPA must adjust the emission rates in the baseline and during compliancemeasurement periods. 

Commenters stated hydroelectric generation in 2012 was approximately 110 percent of Idaho's 

average hydroelectric generation from 1990 to 2012; above-average hydropower generation 

years yield lower emissions from thermal generation; this means that emissions in the 2012 

baseline year were abnormally low. The commenters said below-average hydropower production 

years have historically necessitated the dispatch of additional thermal resources to meet load 

demands and to maintain system reliability with the effect of increasing emissions; by mandating 

emission reductions from the 2012 baseline, the emission-rate goals established for Idaho are 

artificially low. 

Commenters stated given the uncertainty of a multi-state plan, the EPA must reformulate Idaho's 

goal with 70% NGCC capacity factors for its baseline; otherwise, Idaho will not be able to meet 

its 2030 goal with the EPA's targeted amounts of EE and RE without forcing Idaho's utilities to 

run their NGCC plants at 2012 capacity factor levels. 

Commenters stated since the EPA has already determined that running NGCC plants at 70% for 

redispatching purposes is a key component of BSER, the EPA should reformulate Idaho's goal 

with 70% NGCC capacity factors for its baseline; reformulating Idaho's goal in this way would 

encourage cost-effective redispatch of out-of-state coal generation consistent with the premise of 

Building Block 2; reformulating Idaho's goal would also give needed flexibility to Idaho's 

utilities, maximize CO 2 reduction, and minimize adverse reliability and cost impacts to 

customers. 
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Commenters stated the EPA's RE target setting method results in three issues that affect Idaho 

and must be addressed; first, Idaho's in-state carbon free generation percentage already greatly 

exceeds the EPA's proposed renewable portfolio standards ("RPS") when hydro generation is 

included. The commenters said the EPA must treat existing hydropower as RE ensuring that the 

benefits of Idaho's current carbon free generation portfolio are properly accounted for in 

offsetting emissions from affected unit generation. The commenters said second, the amount of 

offsetting renewable energy generation in the EPA's proposed target is disproportionally larger 

than the amount of Idaho's affected unit generation; if the EPA does not treat existing 

hydropower as RE, then at a minimum, Idaho's RE target (existing plus incremental) should be 

capped by the amount of Idaho's affected unit generation. The commenters said third, the EPA's 

Alternative Renewable Energy Methodology Targets completely ignore any cost and reliability 

impacts and should not even be considered. 

Comment 126: ID – The EPA should distinguish between current and future RE, including 

existing hydrogeneration. The EPA should use state-specific growth potentials and adopt more 

stringent goals due to more-achievable EE.

Response 126: See section V.E. of the final rule preamble of the CPP for the EPA’s response to 

this comment and more information about Building Block 3. The EPA is not including demandside energy efficiency (building block four) in the final BSER determination. See section V.A. of 

the final rule preamble of the CPP for the EPA’s response to this comment and more information 

about Building Block 4.

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

Distinguish between current and future RE generation. Commenters encouraged EPA to 

distinguish between current RE generation to establish the baseline emissions and the potential 

for future RE generation to establish the emissions target. Commenters stated that by 

distinguishing between current and future RE EPA can provide a more transparent credit for 

those states that have developed RE and those that have not. Commenters stated that in the 

proposed rule EPA excludes hydroelectric power stating: "inclusion of this generation in current

and projected levels of performance would distort the proposed approach by presuming future 

development potential of large hydroelectric capacity in other states." Commenters were 

concerned that by excluding hydrogeneration, EPA is not capturing a large influence on CO2 

emissions. 

Calculation of existing and future RE. Commenters included a method to calculate existing and 

future renewable energy when setting Idaho's emissions target. Commenters proposed that to 

distinguish between current and future RE, include existing hydrogeneration, and use a more 

state-specific projection of RE potential, EPA adopt a modified method for calculating the 

contribution of RE when setting a state emission target. Commenters proposed an approach with

three parts. 

Commenters stated that first, EPA should establish the baseline emissions for each state using 

the current mix of all generation resources. Commenters stated that EPA should not project 
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future RE development in setting this baseline emission rate. Commenters added that this step 

would capture existing resources, including hydrogeneration, and use actual data to set current 

emissions. Commenters recommended EPA use the most recent year available to calculate 

existing RE, and a 5-year average of hydrogeneration to address year-to-year variability in 

hydropower. 

Commenters stated that second, EPA should use a state based approach to setting RE targets 

proposed by the Union of Concerned Scientists in their report Strengthening the EPA's Clean 

Power Plan. Commenters added that this approach considers the track record of past RE 

development over a recent time frame to set an individualized RE growth target for each state. 

Commenters supported EPA's proposal isolate the RE growth to those resources more 

traditionally included in state-level Renewable Portfolio Standards. Commenters recommended

EPA improve this approach by using state-specific growth potentials. 

Commenters stated that third, EPA should set a State's emission rate target by starting with the 

current baseline emissions rate and decrementing these emissions by applying the potential RE 

development. Commenters stated that this methodology captures the effects of existing 

hydrogeneration but does not presume future hydroelectric development in a manner that would

distort the goal setting exercise. 

Commenters stated that to employ this method EPA could simply divide the current calculation 

of "Existing and New RE" in the block 3 portion of the goal setting exercise. Commenters stated 

that this would treat RE with the same method natural gas combined cycle plants, with distinct 

calculations of 2012 capacity and "under construction". Commenters added that for RE, the EPA 

would simply put existing RE, including hydro, in the 2012 capacity column. Commenters stated 

that then, EPA can create a new category of future RE generation using the state specific growth 

rates proposed by the UCS. Commenters stated that using this methodology transparently 

captures the roll existing hydrogenation plays in Idaho's current and future emissions while also 

preventing any distorting effect of including hydrogeneration in future RE projections. 

State-specific EE potential. Commenters stated that EPA should use state specific energy 

efficiency potential studies when setting emission targets. Commenters recommended EPA use 

state-specific data on energy efficiency potential that document a higher level of EE availability 

than EPA assumes in the proposed rule. Commenters added that each Idaho utility produced a 

potential study in 2013 that calculates the technical, cost-effective, and achievable levels of EE 

through 2032. Commenters added that these studies define the actual levels of available 

efficiency measures, screen these measures for cost-effectiveness unique to Idaho, and consider 

the ability of the utility to actually acquire the savings. Commenters stated that these studies use 

existing EE technologies and currently adopted, or scheduled to go into force, codes and 

appliance standards. Commenters stated that each Idaho utility uses these potential studies in 

formulating the Integrated Resource Plans--a twenty-year plan to find the least cost, least risk 

resources to meet Idahoans' energy needs. Commenters stated that for these reasons, the potential 

studies provide the best available source to establish the level of EE available for the best system 

of emissions reductions adequately demonstrated in Idaho. Commenters stated that because these 

studies document a larger amount of EE available in Idaho, EPA should adopt a more stringent 

emissions target. 
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Commenters stated that to set Idaho's emission target EPA proposes that the contribution of EE 

is 1.5% of sales annually, totaling 3.9% in 2020 and 11.1% in 2029. Commenters stated that each 

of the investor owned utilities in Idaho--Avista, Idaho Power, and Pacificorp-- project a higher 

level of available and cost-effective EE. Commenters stated that combined these utilities serve 

85% of the electric sales in our state. Commenters added that a host of cooperative and 

municipally owned utilities serve the remaining 15% of Idaho's electricity under the umbrella of 

the Bonneville Power Administration. Commenters recommended that for these utilities EPA use 

the EE potential contained in the Northwest Power Planning and Conservation Council 6th 

Power Plan. Commenters stated that each of these potential studies document more available and 

cost-effective EE potential than EPA assumes. 

Commenters stated that in 2013, Idaho Power commissioned an Energy Efficiency Potential 

Study produced by EnerNOC Utility Solutions. Commenters stated that EnerNOC reports the 

results as a percentage of energy sales compared to a baseline assuming no utility sponsored 

efficiency programs. Commenters added that the study documents cumulative EE potential in 

2022 of 18.1% being cost-effective, rising to 22.8% in 2032. Commenters stated that Avista's 

2013 potential study documents similar levels of cost-effective and achievable EE potential for 

the company's service territory in northern Idaho. Commenters stated that PacificCorp, who 

serves southeastern Idaho, also commissioned a potential study in 2013 showing similar results. 

Commenters added that PacifiCorp incorporated these results in the company's 2013 Integrated 

Resource Plan by analyzing a future resource portfolio that presumed annual energy savings 

levels of 2.0%. Commenters stated that this portfolio proved to be the least cost, least risk option 

to meet future energy demands. Commenters stated that the 6th Power Plan calculates by 2030 

that EE can reduce regional energy demand by 26.8%. 

Increase stringency of goals. Commenters stated that these Idaho specific assessments support 

EPA increasing the amount of EE potential used to establish Idaho's emission target. 

Commenters recommended that instead of using 3.9% by 2020 and 11.1% by 2030, EPA use at 

least half of the identified cost-effective potential in 2020 and all the cost effective potential by 

2030. Commenters concluded that this allows time for Idaho utilities to ramp up customer 

engagement and EE program administration to capture all available cost-effective energy 

efficiency. 

Comment 127: ID - The EPA should include hydropower in RE targets, or should cap RE at 

existing affected unit generation

Response 127: See section V.E. of the final rule preamble of the CPP for the EPA’s response to 

this comment and more information about Building Block 3.

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

Commenters stated that hydropower generation is a critical, cost-effective, and carbon-free 

component of both Idaho's and the entire nation's generation mix. Commenters added that the 

contribution of hydro generation to Idaho's low carbon profile is direct and substantial: hydro 

typically accounts for 60-70% of in-state generation on an annual basis and displaces substantial 
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amounts of in-state and out-of-state fossil generation. Commenters stated that given the 

importance of hydro generation as a leading zero-carbon emitting energy source, EPA's failure to 

include or reasonably address existing hydro generation in the proposed rule is arbitrary and 

capricious.

Commenters stated that the exclusion of existing hydro generation particularly affects Idaho in 

the context of EPA's calculation of Proposed RE Targets. Commenters added that under its 

primary RE proposal, EPA establishes each state's RE Target by comparing existing RE 

generation (excluding hydro) as a percentage of total generation (including hydro) against a 

percentage derived by EPA from an average of Renewable Portfolio Standards ("RPS") from 

states within an assigned region. Commenters stated that applying this calculation, EPA assigned 

Idaho an existing RE percentage of 16% and developed the Proposed RE Target based on the 

comparison of that percentage to a 21% regional RPS average. Commenters stated that EPA's 

methodology and resulting Target fails to recognize and ensure proper accounting for Idaho's 

existing hydro generation.

Commenters stated that first, by requiring Idaho to acquire additional incremental RE based on 

other states' RPS rules, EPA ignores Idaho's existing zero-emission hydro generation. 

Commenters stated that when Idaho's in-state carbon-free generation is considered with hydro 

included, the state RE percentage already greatly exceeds EPA's regional RPS target.

Commenters added that for example, during the 2012 baseline year, Idaho produced 15,499 

GWhs of total generation; of that, only 2,044 GWhs was from carbon emitting sources (1,640 

GWhs from affected units) with 13,454 GWhs from non-carbon emitting sources. Commenters

stated that thus, Idaho has already offset more than 6.5 times the amount of its in-state carbon 

emitting generation with existing non-carbon emitting generation within its borders. Commenters

concluded that on this basis, Idaho meets an RPS of 87% zero-carbon emitting energy.

Commenters stated that because 81% of Idaho's non-carbon emitting energy is produced from 

hydro generation, the incremental RE targets as proposed by EPA would effectively result in 

new renewable development that would often displace Idaho hydroelectric generation rather than 

mitigating or reducing CO2 emissions produced by affected unit fossil generation plants. 

Commenters added that if existing hydro generation is reasonably accounted for in developing 

Proposed RE Targets, then such generation would more than offset any incremental RE 

requirement based on regional RPS standards. Commenters concluded that EPA should remove 

the Proposed RE Target from the goal-setting methodology for Idaho. 

Commenters stated that second, EPA's implementation of the RE target calculation for Idaho is 

fundamentally flawed because it is not reasonably tied to the generation and emissions of the 

fossil units that EPA intends to regulate. Commenters added that Idaho and Washington are the 

only two states with Proposed RE Targets that exceed their 2012 affected unit generation. 

Commenters stated that under EPA's current proposal, Idaho's targets significantly exceed every 

other state's targets as a percent of 2012 affected unit generation.

Commenters stated that in fact, Idaho's Proposed RE Target exceeds Idaho's affected unit 

generation by almost 200%. Commenters expounded that this aberration occurs because EPA 

calculates the Proposed RE Targets independent of affected unit generation and emissions. 

Commenters stated that EPA is thus forcing Idaho to offset more than its fair share of emissions, 
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which is inconsistent with the main premise of EPA's BSER method for establishing state goals 

(i.e., offsetting CO2 emissions from affected fossil units). Commenters added that not only does 

this excessive target overstep EPA's authority by purporting to regulate activities unrelated to 

affected source emissions, but it also would lead to the arbitrary and capricious result of 

requiring development of new RE to displace existing zero-carbon emitting generation. 

Commenters concluded that if EPA does not take the appropriate step of eliminating Idaho's 

incremental RE targets based on the state's existing hydro generation, then at a minimum, Idaho's 

Proposed RE Target (existing plus incremental) should be capped by the amount of Idaho's 2012 

affected unit generation. 

Comment 128: ID - The EPA should reconsider its determination to apply BSER to Idaho

Response 128: See sections V.A. and V.D. of the final rule preamble of the CPP for discussion 

of the final BSER determination and building block two, respectively. Also see section VII of the 

final preamble for discussion of updated state goals based on the subcategory-specific emission 

performance rates. EPA baseline data reflects that Idaho has one of the lowest emission rates for 

its affected fossil inventory. The state does have EGUs that meet the applicability requirements, 

so BSER is applied to the state. However, EPA believes that the final CPP BSER is consistent 

with Idaho’s status as a low emission rate state, and the difference between Idaho’s baseline rate 

and the ultimate state goal is low due to the profile characteristics noted below.

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

Commenters stated that Idaho's treatment under the proposed rule illustrates the fundamental 

problems with EPA's approach to determining the Best System of Emission Reduction ("BSER") 

and establishing interim and final performance goals for the state. Commenters added that 

Idaho's existing carbon profile is very low by virtually any measure. Commenters added that 

Idaho has the second lowest total 2012 CO2 emissions in the country; more than 87% of in-state 

energy generated from zero-carbon emitting generation sources; no in-state coal generation; and 

(Idaho has) established and successful Energy Efficiency programs.

Commenters stated that yet EPA's proposed rule establishes a performance goal for Idaho that is 

the second most stringent among all states and requires a further reduction of 33% from EPA's 

baseline CO2 emission rates. Commenters added that the Idaho performance goal is so low, in 

fact, that Idaho Power cannot utilize a brand new, CAA Section 111(b)-compliant natural gas 

combined-cycle ("NGCC") unit, built in 2012, to meet its load. Commenters stated that these 

fundamental structural problems are exacerbated by EPA's failure to accurately characterize 

Idaho's existing NGCC generation in the baseline emission rate, which translates through the 

goal-setting process to further reduce the state performance goal. 

Commenters concluded that EPA should reconsider its determination to apply its building block 

BSER to Idaho and to establish Idaho state performance goals that require reductions beyond 

Idaho's current generation mix. Commenters added that if Idaho did nothing further to reduce its 

carbon emissions, it still would be one of the lowest emitting states (in both absolute amounts 

and in terms of emission rates) in the nation based on the emission rate goals EPA is proposing 
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for the other states. Commenters stated that if EPA does set performance goals for Idaho, it must 

correct the anomalous values for NGCC generation in the baseline emission rate to appropriately 

reflect the critical role of NGCCs in re-dispatch of out-of state coal generation and supporting 

zero-carbon emitting generation.

Comment 129: ID - Idaho should not be subject to a state performance goal

Response 129: The EPA disagrees that Idaho should not be subject to a state performance goal. 

Please see section VII of the final preamble and CO2 Emission Performance Rate and Goal 

Computation TSD for CPP Final Rule supporting the final CPP for the final goals. See response 

to 128.

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

Commenters argued that Idaho should not be subject to a state performance goal. The 

commenters argued that EPA's BSER as applied to Idaho is arbitrary given Idaho's existing 

carbon profile and cannot be reasonably implemented.

Commenters stated that EPA's proposed BSER has not been "adequately demonstrated" for 

Idaho as required by Clean Air Act Section 111, and the proposed rule as it affects Idaho is likely 

to increase carbon emissions from the state due to unreasonable and arbitrary restrictions on the 

use of existing in-state NGCC generation.

BSER doesn't align with generation characteristics in ID. Commenters stated that EPA's 

proposed BSER does not align rationally with the generation characteristics in Idaho. 

Commenters stated that though Idaho has two NGCC plants that EPA considers existing sources 

under the proposed rule, both of those sources (including Idaho Power's Langley Gulch plant 

which just started operation in June 2012) are fully compliant with EPA's proposed Section 

111(b) new source performance standards for NGCCs. Commenters added that as EPA 

recognized in issuing its implementing regulations for Section 111(d), "the degrees of control 

represented by EPA's emission guidelines [for existing sources] will ordinarily be less stringent 

than those required by standards of performance for new sources." 40 Fed. Reg. 53340, 53341 

(Nov. 17, 1975). Commenters stated that EPA's proposed BSER turns this logical relationship on 

its head. Commenters stated that by imposing a state performance goal for Idaho based on 

implementation of activities that are not undertaken at the NGCC plants, but rather "outside the 

fenceline," EPA not only locks in an emission rate assumption for these NGCCs well below the 

111(b) emission rate, but also effectively limits output from those plants based on the interim and 

final goal compliance requirements. Commenters concluded that thus, the Section 111(d) 

emission guidelines for Idaho's existing NGCCs are far more stringent than the comparable 

111(b) standard.

BSER is arbitrary. Commenters stated that the arbitrary nature of EPA's BSER and state 

performance goals for Idaho is further demonstrated by reviewing Idaho's overall carbon profile. 

Commenters added that Idaho's 2012 CO2 emission level was the 2nd lowest emission level in 

the country, second only to Vermont, the only state that is not subject to a state performance goal 

under EPA's proposed rule. Commenters added that Idaho has no in-state coal generation. 
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Commenters stated that in 2012, 87% of Idaho's in-state generation came from zero carbon 

emitting sources, including hydroelectric, wind, solar and geothermal. Commenters added that 

due to the continual addition of generation by new zero-carbon emitting sources within the state, 

by 2020, an even higher percentage of Idaho's in-state generation will be carbon free. 

Commenters stated that Idaho utilities also operate successful Energy Efficiency programs that 

are continually evaluated by the Idaho PUC. Commenters stated that EPA's Notice of Data 

Availability ("NODA") released on October 30, 2014, demonstrates that Idaho already 

produces/saves more MWh through renewable energy ("RE") and energy efficiency ("EE") than 

it generates from affected fossil units. Commenters added that for 2012, EPA reports Idaho as 

producing 2,514,502 MWhs of RE (excluding hydropower and EE) compared with only 

1,639,922 MWhs of affected unit generation. Commenters stated that under the goal-setting 

equation as adjusted in the NODA, by subtracting the fossil emissions that would be displaced by 

existing RE, Idaho's calculated emissions rate goal on a lbs/MWh basis would be a negative 

number. 

Idaho emission profile. Commenters stated that Idaho already surpasses the most stringent 

carbon standard that EPA envisions under the proposed rule for all but one state, and has more 

than mitigated carbon emissions from its two affected fossil units by the amount of RE and EE it 

has already accumulated. Commenters added that in fact, Idaho's existing emission profile is 

closer to Vermont than any of the other states that EPA has assigned state performance goals. 

Commenters concluded that it is arbitrary and capricious for EPA to impose a state performance 

goal proposing a further 30% reduction in Idaho's carbon intensity because Idaho already 

implements an energy mix that achieves the intent of the proposed rule.

BSER not "adequately demonstrated" in ID. Commenters added that in addition, the compliance 

issues that would arise for Idaho in attempting to meet the artificially low state performance 

goals illustrate that EPA has failed to "adequately demonstrate" that its building block BSER can 

be reasonably implemented in Idaho. Commenters stated that in its Legal Memorandum for 

Proposed Carbon Pollution Emission Guidelines for Existing Electric Utility Generating Units, 

EPA describes an adequately demonstrated BSER as "one that can 'be[] shown to be reasonably 

reliable, reasonably efficient, and " reasonably " expected to serve the interests of pollution 

control without becoming exorbitantly costly in an economic or environmental way.'" Id. at 66-

67 (Essex Chemical Corp. v. Ruckelshaus, 486 F.2d at 427, 427 (D.C. Cir. 1973)). 

Commenters stated that EPA's BSER fails to meet any of these criteria with respect to the state 

performance goals imposed on Idaho. Commenters stated that first, EPA's imposition of 

constraints on NGCC generation in Idaho is not "reasonably reliable" because it creates serious 

concerns regarding the ability to meet demand, particularly in low hydro generation years. 

Commenters added that second, the NGCC constraints are not "reasonably efficient" because 

they threaten to prevent the re-dispatch of Idaho utility-owned, out-of-state coal generation to instate NGCCs, which is the most efficient and cost-effective manner of replacing that generation. 

Commenters added that third, the requirement of additional emissions reductions through 

constraints on NGCCs and development of additional renewable generation cannot reasonably be 

expected to achieve emission reductions without exorbitant economic or environmental costs. 

Commenters stated that if EPA requires further emission reductions, Idaho may have to resort to 

alternative energy sources that would increase costs to Idaho customers and the state's overall 

carbon intensity. Commenters added that for example, Idaho Power would be forced to replace 
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efficient existing NGCC generation precluded by the proposed rule through more costly and 

carbon-intensive alternatives. Commenters stated that in order to comply with the rule as 

proposed, Idaho Power would have to: (1) operate its peaking plants more often, at a higher cost 

to consumers and with greater emissions than its NGCC units; (2) rely on market purchases 

which can be costly, unreliable, have unknown carbon profiles, and for which transmission 

capacity may not be available to move the energy to Idaho; (3) replace existing, reliable zerocarbon emitting hydro generation with new intermittent zero-carbon emitting generation sources 

at a higher cost; and (4) build a new NGCC with a potentially higher emission rate under 111(b). 

Commenters stated that such potential outcomes are directly contrary to the intent of the 

proposed rule. Commenters concluded that given the absence of an adequate demonstration of 

EPA's BSER for Idaho and the low carbon intensity Idaho has already achieved, EPA should not 

impose a state performance goal or require further CO2 emission reductions for the state.

Comment 130: ID - The EPA must correct its treatment of Langley Gulch and modify the Idaho 

baseline emission rates and state performance goals

Response 130: The EPA has modified the assumed generation and emissions from the NGCC 

fleet in the state of Idaho by flagging Langley Gulch as under construction and using a capacity 

factor value reflective of a full year’s operation rather than the partial year data reported in 2012. 

See the CO2 Emission Performance Rate and Goal Computation Technical Support Document 

for CPP Final Rule.

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

Commenters argued that EPA must correct its treatment of Langley Gulch and modify the Idaho 

baseline emission rates and state performance goals. The commenters argued that there are 

artificial constraints on Idaho's existing NGCCs and EPA should provide flexibility for increased 

NGCCs in low hydro years.

Commenters stated that the appropriate correction to the baseline emission rate for Langley 

Gulch goes beyond simply fixing a mathematical error. Commenters added that the 

characteristics of Langley Gulch and its role in the generation mix for Idaho and Idaho Power 

demonstrate that the plant should be assigned a higher baseline emission rate in the goal setting 

process.

Commenters stated that first, Langley Gulch was planned and built for the purpose of replacing 

new potential coal-fired generation, consistent with the re-dispatch principles EPA relies on in 

Block 2 of its BSER determination in the proposed rule. Commenters stated that the customer 

load now being served by Langley Gulch had originally been proposed in Idaho Power's 

Integrated Resource Plan submissions to be met through construction of a new coal-fired 

generating unit at the Jim Bridger Power Plant in Wyoming, in which Idaho Power has a partial 

ownership interest. Commenters stated that instead, Idaho Power elected to move forward with 

new NGCC generation at Langley Gulch in anticipation of carbon regulation and reduction 

requirements among other factors.
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Commenters stated that second, the proposed rule is likely to lead to increased demand for 

NGCC generation within Idaho to address reductions in out-of-state coal generation that is a 

significant part of Idaho Power's and Idaho's generation mix. Commenters stated that Idaho 

Power is a part owner of three out-of-state coal plants and relies on out-of-state coal generation 

for approximately 30-40% of its electric supply. Commenters added that under Block 2 

(anticipating redispatch of coal to NGCC generation) of EPA's goalsetting method, the 

Boardman facility in Oregon and the North Valmy facility in Nevada are projected to close 

before 2020. Commenters stated that the most economic and efficient response to those closures 

for Idaho Power customers would be to shift a portion of that company-owned generation to 

NGCC generation within Idaho at Langley Gulch. Commenters added that however, artificial 

constraints on Idaho's existing NGCC generation will prevent replacement of that power with instate NGCC generation and leave no in-state generation sources sufficient to absorb the lost outof-state generation. Commenters stated that despite reducing its reliance on coal-fired generation 

consistent with the intent of the proposed rule, Idaho will have no ability to develop an 

achievable and affordable compliance plan that meets customer demand if state performance 

goals are set so low that they effectively eliminate in-state NGCC generation. Commenters added 

that by way of example, EPA's own IPM modeling projects that Idaho's NGCC plants (Langley 

Gulch and Rathdrum) would operate at an annual average capacity factor of greater than 73% in 

2018 prior to the start of the compliance period. Commenters stated that once the compliance 

period begins in 2020, the IPM model projects NGCC capacity factors dropping to 12.5%.

Commenters stated that third, NGCC generation in Idaho, and at Langley Gulch in particular, 

plays a critical role in leveling the effects of variability in hydropower generation within Idaho 

and the surrounding region. Commenters added that in a normal or typical year, hydroelectric 

generation accounts for approximately 50% of Idaho Power's total generation. Commenters

stated that as a consequence, variations in annual streamflow conditions (which can vary by 

more than 100% from minimum to maximum flow) can have a significant impact on the 

operation of the company's non-hydro generation resources. Commenters stated that for example, 

during a favorable water year, greater hydro generation reduces the need to dispatch fossil 

resources to meet customer loads. Commenters stated that the opposite is true during poor water 

years. Commenters stated that this occurs because Idaho Power dispatches its generation 

resources from lowest cost to highest cost, and Langley Gulch has a dispatch cost that is 

generally higher than the dispatch cost of the company's out-of-state coal-fired resources. 

Commenters stated that therefore, Langley Gulch is often the "marginal" resource that is first 

called upon when hydro generation is low and displaced when hydro generation is high. 

Commenters added that the results of the simulated operating statistics for Idaho Power's hydro 

generation plants and Langley Gulch indicate over the 85 different actual water conditions that 

have been recorded since 1928. Commenters stated that this set of time periods was chosen 

because it is consistent with the method for evaluating hydro generation in the context of rate 

proceedings before the Idaho PUC. Commenters stated that the results demonstrate the impact 

that hydro variability has on NGCC operation and the inverse relationship that exists between 

those two resource types. 

Commenters stated that these dramatic differences in historic hydro generation demonstrate the 

importance of providing flexibility for increased NGCC generation that will be needed during 

below-average hydro generation years. Commenters added that non-hydro renewable energy 

sources, even if their share of generation were expanded as contemplated by EPA under Block 3 
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of its goal-setting method, will simply not be sufficient to replace hydro generation in low-water 

years, and such resources are ill-suited to serve in that role (without NGCC support) due to their 

intermittent nature. Commenters stated that moreover, the role of NGCC generation in 

compensating for low hydro generation will only increase going forward because the proposed 

rule will constrain Idaho Power's ability to offset hydro generation with additional Companyowned out-of-state coal generation. Commenters added that by artificially constraining NGCC 

generation, EPA would guarantee future compliance problems for Idaho because the overly 

stringent performance goal effectively eliminates in-state options for replacement power in years 

with below-average hydroelectric generation.

Commenters stated that in light of these specific characteristics, EPA should correct its treatment 

of Langley Gulch in a manner that provides the flexibility necessary to accomplish the important 

functions of reducing out-of-state coal generation and supporting zero-carbon emitting 

generation. Commenters stated that EPA should consider Langley Gulch as a new NGCC unit 

under Section 111(b) that would be excluded from any requirements for existing units under 

Section 111(d). Commenters added that Langley Gulch is a newly-constructed, state of the art 

NGCC unit that meets all requirements for new generation under the proposed Section 111(b) 

standards and operates at a CO2 emission rate below the rate proposed for new NGCC units. 

Commenters stated that EPA's imposition of effective limitations on the emission rate and output 

from this new Section 111(b) compliant NGCC plant through the Section 111(d) goal-setting 

process for existing units is inconsistent with its own expectations of how Section 111 should 

work in practice. Commenters stated that when EPA issued its regulations implementing Section 

111(d) in 1975, the Agency reasonably anticipated that "the degrees of control represented by 

EPA's emission guidelines [for existing sources] will ordinarily be less stringent than those 

required by standards of performance for new sources." 40 Fed. Reg. 53340, 53341 (Nov. 17, 

1975). Commenters stated that treating Langley Gulch as subject to Section 111(b) would be 

more consistent with the statutory structure and would provide Idaho and Idaho Power much 

needed flexibility to operate Langley Gulch to further the carbon reduction goals of the proposed 

rule.

Commenters stated that if EPA continues to treat Langley Gulch as an existing unit subject to 

Section 111(d), then the most appropriate correction to the plant's baseline operating 

characteristics is to assign an annual capacity factor of 70%. Commenters stated that in the 

context of developing Building Block 2 of its proposed BSER, EPA determined that NGCCs can 

be considered available for use to re-dispatch coal generation within a state up to an annual 

capacity factor of 70% (See 79 Fed. Reg. at 34863). Commenters stated that as explained above, 

Langley Gulch has been used in the past and will be used in the future to replace generation from 

out-of-state coal-fired units owned by Idaho Power. Commenters added that EPA should 

encourage this cost-effective ramping down of coal generation, without regard to whether it is 

occurring within or across state lines, and avoid imposing any artificial constraints on NGCC 

operation that would impede beneficial re-dispatch. Commenters stated that the best way to 

achieve that outcome in Idaho and with Langley Gulch is to assign a baseline capacity factor of 

70% to Idaho's NGCC generation consistent with EPA's Block 2 expectations and to recalculate 

Idaho's state performance goal to reflect this more appropriate representation of NGCC 

generation. Commenters stated that by removing arbitrary barriers to NGCC operation, this 

approach would provide needed flexibility to Idaho's utilities, encourage maximum CO2 

reduction, and minimize reliability and cost impacts to customers.
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Comment 131: IL - The EPA made false assumptions to support the GHG rule

Response 131: See section V of the final rule preamble of the CPP for discussion of the EPA’s

final BSER determination. Also see sections VI and VII for discussion of the subcategoryspecific emission performance rates and state goals, respectively. .

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

Commenters argued EPA has made false assumptions to support the GHG Rule. The 

commenters argued that meeting Illinois' target requires a reduction in use of the Dallman Unit 4, 

however, Section 111(d) of the CAA does not support that EPA can disrupt or redirect existing 

energy dispatch markets.

Commenters stated CWLP is a member of the American Public Power Association (APPA). 

Commenters stated CWLP's new Dallman Unit 4 was one of seventeen new plants that APPA 

used to demonstrate in its comments on USEPA's proposed GHG rule for new EGUs that even 

the newest, cleanest US units do not and cannot come close to meeting the 1,100 lb/MWh limit 

for new plants. Commenters added similarly, since there is little to no technology to reduce 

carbon emissions from existing new plants such as Dallman Unit 4, other than possibly an 

untested, commercially unavailable carbon capture and storage technology, meeting Illinois' 

targeted reduction requires a scheme in which Dallman Unit 4 operates less. Commenters stated 

Section 111(d) of the Clean Air Act does not support a GHG Rule that authorizes the USEPA to 

disrupt or even to redirect the existing energy dispatch market of the Independent System 

Operators like MISO and PJM, created to enable a reliable grid at the most affordable price. 

Commenters concluded moreover, the USEPA has made false assumptions to support the GHG 

Rule.

Comment 132: IL - Illinois' goal should be adjusted for inclusion of the 1600 MW Prairie 

generating station

Response 132: The EPA has adjusted Illinois baseline and goal reflecting the inclusion of Prairie 

State Generating Station as a likely affected EGU.

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

Commenters argued Illinois' goal should be adjusted for inclusion of the 1600 MW Prairie 

generating station.

Commenters stated adjust Illinois' emission reduction goals to account for the absence of any 

representative data for use in baseline and goal determinations. Commenters stated in particular 

the 1600 MW Prairie State Generating Station in Washington County did not reach full and 

expected normal operating levels and emissions in, or prior to, the year 2012. Commenters

recommended that the Illinois emission reduction goals be adjusted to reflect projected normal, 

representative operation and emissions of this facility going forward.
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Comment 133: IL - Heat rate improvements are unrealistic due to parasitic load from control 

equipment

Response 133: 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 argued that heat rate improvements are unrealistic due to parasitic load from control 

equipment.

Commenters stated Illinois has mandated significant reductions in emissions of sulfur dioxide, 

nitrogen oxides, and mercury in rules, such as the Illinois mercury rule, Clean Air Interstate 

Rule, and multi-pollution reduction requirements contained in these rules. Commenters stated the 

additional pollution control equipment required by such rules makes heat rate improvements of 

6% more difficult due to the parasitic load. 

Commenters stated further, there are units in Illinois that have installed pollution control 

equipment since the baseline year of 2012, with more controls either under construction or on the 

way. Commenters stated in at least one case, an affected source owner has noted the loss of 

nearly 10% of its net output since 2012 due to the parasitic load. Commenters concluded it 

appears unrealistic to assume that this unit, and any like it, could achieve a cumulative heat rate 

improvement of around 16% over the base year.

Comment 134: IL - BB2

Response 134: See section VI.A of the final rule preamble of the CPP and the CO2 Emission 

Performance Rate and Goal Computations TSD for CPP Final Rule.

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

Commenters supported the increased utilization of NGCC's; however aside from the lack of 

authority for a state environmental agency to compel an increased dispatch of NGCC units, 

USEPA's calculation to determine Building Block 2 that would increase utilization of such units 

to 70% for the Holland Energy Facility (ORIS code 55334) in Beecher City, Illinois is in error. 

The commenters said as an example, USEPA assumed that the entire capacity for the steam 

turbine (ST) could be dispatched at 70%; the facility is limited by its CAAPP (air) permit; in 

fact, each duct burner on the steam turbine has a firing limit of 1,500 hours per year limit - this 

additional MW capacity is unavailable for more than 80% of the year. 

Commenters stated the units are also limited by its NPDES (water) permit. The commenters said 

even though the facility is equipped with a closed cycle cooling tower, the NPDES Permit has 

thermal effluent limitations that cannot be exceeded. The commenters said if the effluent 

temperature exceeds the limit and the facility is forced to stop discharging, the facility could 
157

continue to run for several hours; however, the facility may have to discontinue operation if 

temperatures (discharge and/or upstream river temperature) do not come down. The commenters

said the NPDES permit also prohibits the discharge from the permitted outfall to the Kaskaskia 

River if the river flow is less than 10 cfs; this is effectively a shutdown requirement. The 

commenters said these water issues are not unique to WVPA's NGCC facility; these errors need 

to be corrected and the goals adjusted accordingly. 

Comment 135: IN - Indiana should have higher emission rate targets

Response 135: For the EPA’s response to this comment, see the CO2 Emission Performance 

Rate and Goal Computation TSD for CPP Final Rule supporting the final CPP.

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

Commenters did not support utilizing EPA's methodology to set emission rate standards, 

however the commenters argued Indiana should receive higher emission rate targets based on 

more reasonable assumptions.

Commenters did not support utilizing EPA's existing methodology to set emission rate targets, 

the company examined the interim and final emission rate targets using more realistic 

assumptions. Commenters stated the results of NIPSCO's 2012 baseline year analyses suggest 

that, based on EPA's methodology and more realistic assumptions, Indiana's 2020-2029 interim 

rate target should be set no lower than 1,786 lb CO2/MWh, and Indiana's final emission rate 

target should be set no lower than 1,753 lb CO2/MWh. Commenters stated NIPSCO conducted 

similar analyses using the 2011 data released as part of EPA's October 28, 2014 NODA. 

Commenters stated applying more reasonable assumptions to the 2011 baseline year data 

indicates that Indiana's 2020-2029 interim rate target should be set no lower than 1,853 lb 

CO2/MWh, and Indiana's final emission rate target should be set no lower than 1,824 lb 

CO2/MWh. Commenters did not support utilizing EPA's exiting methodology to set emission 

rate standards. Commenters stated these calculations are provided to show how Indiana's rates 

would have been set using more reasonable assumptions in EPA's existing methodology.

Comment 136: IN - Indiana should receive greater mass allocation

Response 136: See sections V.A and VII.C 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 argued that Indiana should receive greater mass allocation, TSD does not account 

for projected future increases in Indiana generation.

Commenters stated NIPSCO has reviewed the newly released TSD, "Translation of the Clean 

Power Plan Emission Rate-Based CO2 Goals to Mass-Based Equivalents," and does not agree 
158

with EPA's suggested historical calculation method for states that choose mass-based 

compliance. Commenters added the method presented in the TSD does not adequately account 

for the projected future increase in Indiana generation. Commenters stated the State Utility 

Forecasting Group reported to the Indiana Utility Regulatory Commission in December 2013 

that electricity requirements in the state would grow at a rate of 1.17% annually until the year 

2031. Commenters added EPA has embedded EE requirements in the proposed rate targets, and 

multiplying the targets by a mass equivalent generation level that is artificially lower because it 

already incorporates the effects of EE would constitute double counting. Commenters stated for 

this reason, a 1.17% annual growth rate is more appropriate than the suggested EIA Electricity 

Market Module regional value of 0.45%. Commenters added practically speaking, EE displaces 

future growth; it does not replace existing generation. Commenters concluded NIPSCO suggests 

that EPA clarify its method of calculating mass allocations and allow state-specific modeling of 

electric growth.

Comment 137: IN - The EPA incorrectly applied BSER - The EPA is not legally allowed to 

regulate outside the fence. The EPA's assumptions across the Building Blocks are incorrect and 

unrealistic.

Response 137: See sections V.A., V.B., V.C., V.D., V.E. of the final rule preamble of the CPP 

for the EPA’s response to this comment and the CO2 Emission Performance Rate and Goal 

Computation TSD for CPP Final Rule supporting the final CPP for the final goals.

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

Commenters argued EPA incorrectly applied BSER, is not legally allowed to regulate outside the 

fence, and their assumptions across the Building Blocks are incorrect and unrealistic.

Commenters stated after applying the four Building Blocks to Indiana, EPA calculates a state 

interim emission rate target of 1,607 lb CO2/MWh from 2020-2029 and a final emission rate 

target of 1,531 lb CO2/MWh by 2030. Commenters stated NIPSCO believes that Indiana's state 

targets are overly aggressive and are based on faulty assumptions underlying the four Building 

Blocks. 

Commenters stated EPA cannot expect coal-fired EGUs to achieve a 6 percent improvement in 

heat rates. Commenters added industry analyses indicate that heat rate improvement potential is 

between 1 percent to 2 percent across the industry. Commenters stated economically achieving a 

70 percent capacity factor for NGCC units is unrealistic. Commenters added the highest 

statewide average NGCC capacity factor in Indiana was 53 percent in 2012. Commenters stated 

this uncharacteristically high level of NGCC generation in Indiana occurred during a year when 

natural gas prices were near historic lows. Commenters stated therefore, NISPCO believes that 

the maximum expected statewide average capacity factor for Indiana's NGCC plants should be 

no higher than the demonstrated 53 percent. Commenters stated EPA's assumptions regarding 

energy efficiency deployment in Indiana are grossly exaggerated. Commenters stated the Agency 

believes that Indiana can achieve annual EE savings of 1.5 percent, eventually resulting in a 

cumulative savings of approximately 11 percent in 2029. Commenters concluded the annual 
159

incremental rate of 0.58 percent EE savings achieved by Indiana in 2012 is the highest 

incremental rate EPA should assume and is in line with the EPRI study.

Comment 138: IN - is uniquely disadvantaged in meeting EE targets due to an Indiana law 

allowing industrial customers to opt out of EE programs

Response 138: The EPA has not included demand-side energy efficiency (building block four) 

in the final BSER determination. 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 argued NIPSCO is uniquely disadvantaged in meeting EE targets due to an Indiana 

law allowing industrial customers to opt out of EE programs.

Commenters stated on March 28, 2014, Indiana Senate Enrolled Act 340 (SEA 340) became law 

(codified as IC 8-1-8.5-9 et seq), allowing qualified industrial customers as defined by the statute 

to opt out of EE programs in Indiana. Commenters added for the period of 2012-13, 53 percent 

of the energy consumption savings achieved by the Core programs in Indiana were attributed to 

commercial and industrial customers. Commenters stated in NIPSCO's service territory, 

industrial customers represent approximately 50 percent of energy usage. Commenters stated due 

to the significant percentage of industrial customers that have opted out of Indiana's EE 

programs, the significant percentage of Indiana EE program savings already achieved by 

industrial customers, and the significant percentage of NIPSCO's customers that are industrial 

users, NIPSCO is uniquely disadvantaged in meeting the EE targets established in the Proposed 

Rule.

Comment 139: IN - Indiana demand-side goals costly and unfeasible; Indiana is penalized for 

past improvements

Response 139: The EPA has not included demand-side energy efficiency (building block four) 

in the final BSER determination. 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 argued that Indiana's demand-side EE goals would be incredibly costly to achieve, 

may not be feasible. The commenters also argued that Indiana is penalized for past 

improvements in energy efficiency.

EE goals. Commenters stated that EPA expects Indiana to achieve cumulative reductions in 

residential, industrial, and commercial energy usage of 3.2 percent by 2020 and 11.1 percent by 

2030. Commenters added that these numbers are based on a set of flawed assumptions about 

Indiana's electricity sector and would be incredibly costly to achieve. Commenters stated that 
160

IUG proposes EPA conduct a more realistic appraisal of the potential for realizable energy 

savings in Indiana based on state-specific forecasts. Commenters stated that IUG also proposes 

EPA take Indiana's existing demand-side efficiency programs into account when crafting their 

expectations for future energy savings.

Commenters added to better understand why EPA's 1.5 percent number is inappropriate for 

Indiana, it helps to understand the history of demand-side efficiency programs in our state. 

Commenters stated in December 2009, the IURC mandated that Indiana utilities implement a set 

of statewide demand-side management programs ("CORE programs") to achieve energy savings 

equivalent to a 2 percent reduction in sales by the year 2019, with interim goals. 

Commenters stated according to the evaluation completed to measure energy savings through the 

CORE programs, in 2012 (the first year such programs were offered on a statewide basis) 

Indiana achieved an "overall verified program realization rate of 71 percent for kWh and 60 

percent for kW." Commenters stated in other words, through its statewide programs, Indiana 

achieved less than 0.7 percent verified energy savings in 2012. Commenters added Indiana has a 

very limited history in large-scale energy efficiency programs, making it difficult to know the 

long-term achievability of energy efficiency goals. Commenters stated yet, in spite of these facts, 

EPA calculated that Indiana was one of twelve states that "have either achieved" or have 

established requirements that will lead them to achieve "annual incremental savings rates of at 

least 1.5 percent of the electricity demand that would otherwise have occurred." Commenters

concluded the existence of a state requirement to achieve 1.5 percent savings at some point in the 

future is a far cry from demonstrating that requirement's feasibility or cost-effectiveness.

Commenters added recent events in Indiana support IUG's skepticism towards EPA's aggressive 

savings target. Commenters stated this year, the Indiana General Assembly elected to reevaluate 

the specifics of the state's energy efficiency programs. Commenters stated Senate Bill 340 

established a sunset for the aforementioned goals, effective December 31, 2014. Commenters

added had those benchmarks remained in place, a study by the Energy Center of Wisconsin 

estimated the cost of compliance would have spiked to $200 million in 2015 and $549 million in 

2019.

Past improvements. Commenters stated Indiana has already taken advantage of many of the 

easiest opportunities to improve statewide energy efficiency. Commenters stated for instance, in 

addition to utility-specific programs, through the CORE programs created by the IURC in 2009, 

utilities and stakeholders have been aggressively marketing residential home energy audits; lowincome weatherization; building assessments at schools; residential lighting improvements; and 

commercial & industrial prescriptive rebates for several years. Commenters stated these efforts 

are widespread and impactful; in fact, the SUFG cites utility-sponsored conservation efforts as 

having a major influence on the overall resource needs of Indiana in 2013. Commenters stated to 

date, the vast majority of verified savings have come from residential lighting improvements and 

commercial & industrial prescriptive rebates; both of these programs promise diminishing 

returns in the years to come.

Commenters stated in the case of residential lighting improvements, savings are realized when 

the light bulb is changed. Commenters added the opportunities for year-over-year improvements 

are limited by the nature of the technology. Commenters stated in the case of commercial & 
161

industrial prescriptive rebates, major retrofits like equipment replacement or building 

improvements are also often one-time opportunities. Commenters added as more and more major 

efficiency improvements are implemented by a facility, improvements tend to yield fewer 

savings per dollar invested. Commenters stated other measures besides lighting and equipment 

improvements have no track record of being sustained and/or growing annually, or face 

consumer acceptance problems. Commenters stated inexplicably, EPA assumes that existing 

opportunities for improvements in energy efficiency will be continuously available for a decade.

Commenters stated federal lighting standards will make it harder for Indiana to include 

residential lighting improvements in its 111(d) Plan. Commenters stated specifically, the Energy 

Independence and Security Act of 2007 (H.R. 6) set new light bulb efficiency standards that have 

largely resulted in the phase-out of traditional incandescent bulbs. Commenters stated other 

federal building codes and efficiency standards will have a major impact on the marketplace for 

appliances and household products in the coming years. Commenters stated these standards will 

result in energy savings in Indiana, but Indiana cannot claim those savings in its 111(d) Plan 

because those savings programs are not "realized exclusively through the adoption and 

implementation" of Indiana demand-side efficiency programs. Commenters concluded under the 

proposed rule, Indiana is effectively being penalized for the state's past investments in energy 

efficiency.

Comment 140: IN - Indiana should receive credit for early EE savings

Response 140: The EPA has not included demand-side energy efficiency (building block four) 

in the final BSER determination. See section V.A. of the final rule preamble of the CPP for the 

EPA’s response to this comment and more information about Building Block 4.

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

Commenters argued that EPA should allow credit for early action under existing state EE 

programs.

Commenters stated EPA proposes that emission reductions achieved during a plan performance 

period that result from an existing state program may apply toward its required state emission 

performance target. Commenters stated EPA should expand the scope of the existing programs 

provisions of its Proposed Rule to give the broadest favorable treatment possible to EE actions 

taken that result in reduced CO2 emissions regardless of whether those actions were taken prior 

to issuance of the Proposed Rule. Commenters stated to not allow early action would create a 

perverse incentive to delay EE programs and wait for credit.

Commenters added EPA and states could apply the 'Weight of Evidence' concept offered in 

Section VI above to capture early action.

Comment 141: IN - Indiana's EE goal is unreasonable
162

Response 141: The EPA has not included demand-side energy efficiency (building block four) 

in the final BSER determination. See section V.A. of the final rule preamble of the CPP for the 

EPA’s response to this comment and more information about Building Block 4.

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

Commenters stated that for Indiana, EPA determines the percentage of potential avoided MWh 

sales from EE savings to be 3.20 percent in 2020, increasing to 11.11 percent in 2029. 

Commenters added that the 11.11 percent EE goal is among the highest levels assumed by EPA. 

Commenters stated that EPA's calculations start with approximately 3,600,000 MWhs for EE in 

2020 and increases to about 12,600,000 MWhs in 2029, which means that half of the CO2 

emissions rate reductions for Indiana are coming from future EE. Commenters concluded that 

these are fairly high numbers and extremely unrealistic, particularly given the unique difficulties 

that co-ops have achieving energy reductions from EE in general, and Hoosier Energy's specific 

experience.

Comment 142: IN - A regional compliance plan would be required for Indiana's compliance due 

to the reduction in Merom station capacity factor

Response 142: See section V.E. of the final rule preamble of the CPP for the EPA’s response to 

this comment and more information about Building Block 3.

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

Commenters stated that Hoosier Energy's analysis determined that because of the reduction in 

the capacity factor at Merom, insufficient power will be generated to meet demand; its system 

will be short 3.7 million MWhs annually. Commenters added that for each MWh that Indiana 

does not generate through RE or does not reduce through an EE program (in a portfolio 

approach), Indiana must reduce 5 MWhs of coal. Commenters stated that unless Indiana and 

Illinois participate in a regional compliance plan, Hoosier Energy's NGCC and most of its RE in 

Illinois cannot be utilized for CPP compliance in Indiana.

Comment 143: IN - The EPA should not base Merom station capacity factor on 2012 operations

Response 143: For the EPA’s response to this comment, see the CO2 Emission Performance 

Rate and Goal Computation TSD for CPP Final Rule supporting the final CPP. The EPAdoes 

not make any unit-level assumptions or requirements in regards to plant operation levels. The 

building blocks are assessed regionally in the final rule. See preamble section VI for a 

discussion of unit-level outage, why EPA believes it does not disrupt its quantification of sourcecatgory rates, and the unit-level outage impact test it conducted for units nationwide to determine 

if any corresponding state-level adjustments were necessary.

The following are summaries of the specific public comments under this comment:
163

Commenters stated that Hoosier Energy relies almost exclusively on the state of the art Merom 

station for baseload generation. Commenters stated that as proposed, the CPP will force Merom 

units to operate significantly less even though they are some of the lowest emitters of traditional 

pollutants in the country. Commenters stated that according to technical support documents, EPA 

assumes that Merom operates at a capacity factor of 59 percent based solely on 2012 operations -

a year in which significant pollution control upgrades were being made. Commenters stated that 

this is an arbitrary, unfair and inaccurate capacity factor. Commenters added that for example, 

the net capacity factor for Merom was 77% in 2011 and 75% in 2010 when major upgrades were 

not being performed. Commenters stated that assuming the Indiana Department of 

Environmental Management (IDEM) employs the rate to mass based equivalent conversion 

provided for in EPA's November 2014 technical support document, Indiana will have an interim 

mass equivalent of 76,689,000 metric tons of CO2. Commenters stated that if IDEM apportions 

this CO2 budget across Indiana's coal-fired plants based solely on 2012 operations, Merom's 

capacity factor would be reduced to 42 percent. Commenters concluded that this severe reduction 

in Merom's generation will significantly hamper Hoosier Energy's ability to provide reliable, 

affordable power to its members.

Comment 144: IN - Data corrections for coal-fired facilities; concern for Indiana ratepayers

Response 144: The EPA has adjusted the generation and emissions for the state up to reflect a 

representative full year’s operation for the Edwardsport facility recognizing the comment that it 

began operation part way through 2012 and thus 2012 data was not representative. See section 

VI of the final rule preamble of the CPP and the CO2 Emission Performance Rate and Goal 

Calculation TSD for CPP Final Rule for further discussion.

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

Commenters offered corrections to inaccurate data for coal-fired facilities and expressed concern 

for Indiana ratepayers if the Edwardsport IGCC plant is prevented from fully operating.

Commenters stated based on a review of U.S. EPA's technical support documents included as a 

part of the proposed rule, Indiana has identified several data points that are inaccurate specific to 

a number of active coal-fired facilities currently located in the state. Commenters added this 

includes the classification of some of the state's facilities as "peakers". Commenters stated there 

are additional concerns associated with the 2012 emissions data. Commenters added for 

example, Duke Energy's Edwardsport Generating Station is a new coal gasification facility sited 

adjacent to the old Edwardsport power plant that had coal fired boilers. Commenters stated the 

old plant ceased operation prior to 2012 and the new Edwardsport IGCC plant was in the initial 

start of operations in 2012. Commenters stated the emissions data U.S. EPA used in the TSD for 

Edwardsport is in no way reflective of actual operating conditions and should be adjusted when 

evaluating Indiana's state goal. Commenters expounded this facility ran very little during 2012, 

yet U.S. EPA data assumes this facility was operating at full capacity. Commenters added the 

Edwardsport IGCC facility was conducting tests for operation and was not yet fully in service in 

2012. Commenters stated furthermore, the Edwardsport IGCC used natural gas instead of coal 

for a significant portion of the time it was operational in 2012. Commenters stated the future 
164

emission rate for this facility will likely be greater than the 2012 levels because this facility is 

designed to run primarily on synthesized gas from coal. Commenters stated Indiana is concerned 

that the current emission rate targets for Indiana under the Clean Power Plan could prevent the 

Edwardsport IGCC plant from fully operating according to its original design. Commenters

stated if this happens, Indiana ratepayers will bear more than $2.5 billion in construction costs 

for this facility without receiving the full benefits expected when the initial investment in the 

plant was originally approved in 2007. Commenters stated under Indiana law and past orders 

from the IURC, the utility may recover approved construction costs even if the facility never 

operates to serve ratepayers. Commenters concluded preventing the Edwardsport IGCC plant 

from fully operating could represent a significant stranded cost issue for Indiana ratepayers, 

which is explicitly contrary to the intent of the rule.

Comment 145: IN - 70% capacity factor for NGCCs overestimates Indiana's capabilities

Response 145: See section V.D. of the final rule preamble of the CPP for the EPA’s response to 

this comment and more information about Building Block 2.

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

Commenters argued a 70% capacity factor for NGCCs overestimates Indiana's capabilities.

Commenters stated in the year 2012, natural gas prices were at record lows. Commenters added 

natural gas powered EGUs were able to sell power to RTOs at lower prices than coal-fired EGUs 

and had a larger piece of the power sector. Commenters stated it was also a very hot summer in 

Indiana, and energy usage was above normal levels. Commenters stated even under these 

conditions, in which there was a financial advantage to maximize natural gas power, NGCC 

capacity usage in Indiana was only at 53% when averaged between all the NGCC units. 

Commenters stated this indicates that BSER for Indiana NGCCs should be closer to 53% than 

70%. Commenters stated the Noblesville facility is a former coal-fired unit converted to a NGCC 

unit by the addition of combustion turbines, and is less efficient. Commenters stated the 

Noblesville unit ran at a 29% capacity factor in 2012, despite the favorable natural gas price 

conditions of that period. Commenters added while new NGCCs built in Indiana would most 

likely be able to operate at a 70% capacity factor and help Indiana reach the BSER 

determination, this would require Indiana to bring all new NGCC units in under both Section 

111(b) and 111(d) to be able to meet the BSER. Commenters concluded it is unclear whether a 

facility can be regulated under both elements of Section 111 and it most certainly was not the 

intention of the CAA to force states to build new facilities in order to meet BSER requirements 

under 111(d).

Comment 146: IN - Insufficient technical information is provided showing how a 6% heat rate 

improvement is achievable; utilities should receive credit for implemented improvements

Response 146: See section V.C. of the final rule preamble of the CPP for the EPA’s response to 

this comment and more information about Building Block 1.
165

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

Commenters argued there is not sufficient technical information to show how a 6% heat rate 

improvement is achievable. The commenters argued many utilities have already implemented 

suggested heat rate improvements and should be given credit.

Commenters stated U.S. EPA erroneously relied on the Sargent & Lundy report and incorrectly 

applied cumulative improvements in a manner inconsistent with how the study was conducted. 

Commenters added the study was intended as a guide for EGU operators to use to evaluate 

potential areas for heat rate improvements. Commenters stated in the study, it was assumed many 

times that the technology being evaluated was older or had not already been already replaced 

with more up-to-date technology. Commenters concluded however, many Indiana utilities have 

already implemented the suggested heat rate improvements and should be given credit in the 

proposed rule for those improvements.

Comment 147: IN - Indiana is not positioned to address the RE goal within the proposed 

timeline (due to lack of infrastructure)

Response 147: See section V.E. of the final rule preamble of the CPP for the EPA’s response to 

this comment and more information about Building Block 3.

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

Commenters argued due to lack of infrastructure, Indiana is not positioned to address the RE 

goal within the proposed timeline. 

Commenters stated in order for Indiana to meet the renewable goal set by U.S. EPA in Building 

Block 3, the state would essentially have to double its wind farm capacity. Commenters added 

however, current infrastructure does not allow all of the energy currently being produced by 

Indiana's wind farms to reach the grid, so additional wind energy capacity still would not 

increase Indiana's renewable energy share. Commenters stated until new transmission capacity is 

in place, it is impossible for wind energy production to increase. Commenters stated transmission 

lines are being scheduled for installation by the Midcontinent Independent System Operator 

(MISO) in the coming years to address the current problem, but the interim time frame for this 

rule does not give sufficient time for adequate infrastructure to be put in place. Commenters

concluded based on the factors described above, Indiana is not in a position to adequately 

address the goal proposed by U.S. EPA for Building Block 3 within the proposed rule's 

timelines.

Comment 148: IN - Additional legislative action and time will be required to achieve 

compliance with the RE goal

Response 148: See section I.A. of the final rule preamble of the CPP for the EPA’s response to 

this comment.
166

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

Commenters argued that additional legislative action and time will be required to achieve 

compliance with the RE goal.

Commenters stated the RE goal for Indiana of 7,547,087 MWh (approximately 7% of total 

generation of 121,794,969 MWh) will be difficult to achieve. Commenters stated Indiana has a 

Voluntary Clean Energy Portfolio Standard (VCEPS) Program. Commenters added none of the 

Indiana utilities have developed renewable generation using the VCEPS Program. Commenters

concluded additional legislative action in Indiana will be required to achieve state compliance 

with the Clean Power Plan's RE goal, which could take a considerable amount of time to 

implement.

Comment 149: IA - targets, applicability clarifications

Response 149: For the EPA’s response to this comment, see the CO2 Emission Performance 

Rate and Goal Computation TSD for CPP Final Rule supporting the final CPP. Also the EPA 

agrees with the commenters and the MP&W Muscatine Plant #1 Generator 7 is excluded because 

the nameplate capacity is equal to or less than 25 MW.

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

Commenters stated EPA should strengthen the overall stringency of Iowa's interim and final 

emissions rate target. The commenters said since 2012 - EPA's proposed baseline year - Iowa 

utilities have 1) retired or announced for retirement some coal-fired power plants, 2) converted 

or announced for conversion some coal plants to natural gas, 3) announced and begun 

construction on a new, natural gas plant, and 4) built or announced construction of significant 

new wind generation; these changes are underway and will largely be concluded by 2016 or 

2017. 

Commenters stated Iowa will likely be in compliance with the proposed rule before the plan 

performance period even begins in 2020 - and will potentially be in compliance before Iowa is 

required to submit a state compliance plan in 2016. 

Commenters stated that the proposed rule generated significant confusion regarding the 

inconsistencies in discussions of applicability criteria and requested clarification on the 

applicability status of MP&W's Unit 7. Commenters also supported the approach for 

applicability presented in the preamble and requested that MP&W Unit 7 be designated an 

excluded unit due to its small size.

Comment 150: IA - The EPA underestimated Iowa's RE potential; BB3 would be based on 

technical potential and economic potential for RE development; Iowa RE target is not stringent.
167

Response 150: See section V.E. of the final rule preamble of the CPP for the EPA’s response to 

this comment and more information about Building Block 3.

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

Commenters argued EPA has underestimated Iowa's RE potential, and the state's ability to 

reduce carbon pollution. The commenters argued that Building Block 3 should be based on 

technical potential and economic potential for RE development, and that the Iowa RE target is 

not stringent.

Commenters stated as currently proposed, EPA's regional approach for establishing renewable 

energy targets under Building Block 3 significantly underestimates Iowa's cost effective 

renewable energy potential and the state's ability to reduce carbon pollution. Commenters stated 

the Council recommends that EPA base Building Block 3 on technical potential and economic 

potential for renewable energy development, instead of or in addition to the policy basis that 

EPA has proposed to use. Commenters added the policy basis "the averaging of state RPS 

policies" provides a reasonable starting point for Building Block 3, but the building block should 

be strengthened by adding technical and economic potential analysis. Commenters stated the 

alternative approach proposed by EPA in the Alternative RE Approach Technical Support 

Document is a substantially improved approach for Building Block 3, and the Council comments 

on that approach in more detail below. 

Alternative approach. Commenters stated under the proposed approach, EPA developed regional, 

renewable energy targets based on states' average RPS standards. Commenters added EPA then 

capped renewable energy targets for states that were performing at levels over this regional 

average. 

Commenters stated overall, the proposed approach would result in 7% of total U.S. electricity 

sales derived from renewable energy in 2020 and 12% in 2030. Commenters stated the proposed 

approach would also result in higher levels of renewable energy in most, but not all states. 

Commenters added Iowa is one of four states where the application of the proposed approach for 

Building Block 3 results in less renewable energy during the compliance period than the state 

had actually installed and in operation in the 2012 baseline year.

Commenters stated under Step 4b of the building block as proposed, Iowa would generate just 

under 8,566 GWh of existing and incremental renewable energy in 2020, and that is held static 

from 2020 to 2030. 

Synapse Energy Analysis. Commenters stated the Council conducted an analysis of Iowa's 

compliance potential with this current and planned renewable wind generation using Synapse 

Energy Economics' Clean Power Plan Planning Tool ("CP3T"). Commenters stated the Council 

made the following modifications to inputs.

Commenters stated Iowa's 2012 actual wind generation of 14,183 GWh was maintained from 

2013 to 2015 and then increased to 18,536 GWh annually to reflect the addition of 

MidAmerican's two wind projects (totaling 1,212 MW). Commenters added a reasonable 41% 

capacity factor was assumed. 
168

Commenters stated compared to the 8,566 GWh renewable energy target for Iowa currently 

proposed in Building Block 3, Iowa will actually generate "at a minimum" 18,536 GWh in 2020. 

Commenters added this is almost 10,000 GWh more than the level produced by the proposed 

Building Block 3 methodology.

Commenters stated compared to the 8,566 GWh renewable energy target for Iowa currently 

proposed in Building Block 3, Iowa will actually generate "at a minimum" 18,536 GWh in 2020. 

Commenters stated this is almost 10,000 GWh more than the level produced by the proposed 

Building Block 3 methodology. 

Commenters stated this addition of wind generation alone reduces Iowa's emissions rate from 

1,551 lbs/MWh in 2015 to 1,360 lbs/MWh in 2016. Commenters stated using default 

assumptions for load growth (the load growth projected from AEO 2013), Iowa's emissions rate 

is 1,425 lbs/MWh in 2030, assuming no other compliance options are included (no energy 

efficiency, no coal plant retirements or conversions, etc.). Commenters stated in other words, 

Iowa will meet half or more of its emissions target well before 2020, with wind energy already 

existing and planned to be installed before 2020. 

Commenters stated if the basic energy efficiency savings in Building Block 4 are also included 

in the CP3T model, Iowa's emissions rate is 1,294 lbs/MWh in 2020 and 1,178 lbs/MWh in 

2030. Commenters added, these energy efficiency savings are likely to occur in Iowa because the 

state has a supportive policy framework where reasonably high levels of annual savings are 

achieved (e.g., 1% or more annually). Commenters concluded as a result, existing/planned 

renewable energy and expected energy efficiency savings would allow Iowa to exceed the 

interim and final goal by a comfortable margin.

Commenters stated Iowa has the technical potential to achieve levels of renewable energy 

development that are an order of magnitude greater than what EPA calculated in Building Block 

3.

NREL Study. Commenters stated the most complete recent study, the Renewable Electricity 

Futures Study, was released by the National Renewable Energy Laboratory in 2012. Commenters

stated EPA relied upon data from this study in its Alternative RE Approach Technical Support 

Document. Commenters stated in this study, NREL identified 1,723,588 GWh of wind energy 

potential for Iowa and 7,029,897 GWh of solar PV potential (urban utility-scale, rural utilityscale, and rooftop). Commenters stated this translates to 571 GW of wind and 4,043 GW of 

solar. Commenters added the NREL study also identified additional potential from hydropower 

and bio-power. Commenters concluded wind and solar alone, however, account for 8,753,485 

GWh of renewable energy technical potential in Iowa. 

Commenters stated the Renewable Electricity Futures Study is consistent with other major 

national studies examining the state's potential for renewable energy development, such as the 

Department of Energy's 20% Wind Energy by 2030 report. Commenters stated in this report, 

DOE projected that approximately 300 GW of wind capacity would be needed to bring the U.S. 

to 20% wind. Commenters added of this, 251 GW would be land-based and 54 GW would be 

offshore. Commenters stated certain states contributed significantly more wind capacity than 
169

others, by hosting 10 GW or more wind capacity. Commenters stated Iowa is one of those states 

and, by 2030, would host approximately 20 GW of wind capacity. 

Commenters stated DOE also provided a projected schedule of wind capacity additions by state. 

Commenters stated according to this schedule, Iowa was forecast to have 2,930 MW of installed 

capacity by 2016; 7,960 MW by 2020; and 19,910 MW by 2030. Commenters stated Iowa is 

already well ahead of this schedule: Iowa will have over 6,000 MW of wind capacity by 2016, 

more than twice the projected amount by DOE. Commenters concluded therefore, Iowa's 

technical potential for renewable wind is not a distant or theoretical concept, but is clearly 

achievable and is being achieved now. 

Current IA goal. Commenters stated EPA's proposed renewable energy goal for Iowa under 

Building Block 3 does not require Iowa to develop any of the technical potential projected by 

DOE or NREL's analysis. Commenters stated furthermore, the state's final target under the 

proposed rule would require Iowa to develop very little of this potential, even if Iowa complies 

with the proposed rule with wind energy alone. Commenters added, if Iowa uses no other 

compliance option than wind - no efficiency, no coal plant retirements, no heat rate 

improvements, no conversions to natural gas - the wind energy that will be installed before 2020 

will reduce Iowa's emissions rate to between 1,354 lbs/MWh (no load growth) to 1,425 lbs/MWh 

(load growth) in 2030. 

Commenters stated, Iowa is already retiring coal plants, converting others to gas, and can be 

expected to realize savings from existing and ongoing energy efficiency programs. Commenters

stated these current and planned actions, along with existing wind installed prior to 2020, are 

likely to meet Iowa's entire compliance obligation. Commenters concluded as a result, it is 

unlikely that the proposed Clean Power Plan will require or encourage Iowa to install much or 

any new wind generation for compliance purposes.

Commenters stated according to the Council's analysis using selected inputs in the M.J. Bradley 

& Associates' Clean Power Plan Evaluation Tool, increasing Iowa's annual incremental savings 

rate ("maximum ramp-up level") from 1.5% to 2% and the pace of improvement ("ramp-up 

step") from 0.2% to 0.25% would change Iowa's 2020 interim emissions rate target under the 

proposed rule from 1,341 lbs/MWh to 1,316 lbs/MWh and the state's final goal in 2030 from 

1,301 lbs/MWh to 1,262 lbs/MWh. 

Commenters stated while the above modifications result in a modest increase to Iowa's targets, 

they are important changes for EPA to make, strengthening Iowa's targets will ensure that the 

state has a meaningful compliance obligation under the proposed rule. Commenters concluded it 

will also help ensure that Iowa is maximizing cost-effective and technically feasible energy 

efficiency savings.

Commenters stated by using adjusted, regionally-based renewable energy generation targets to 

establish Iowa's emissions rate goal for 2030, EPA set Iowa's final emissions goal at 1,301 

lbs/MWh. Commenters stated this amounts to a 16% reduction from its current emissions rate of 

1,552 lbs/MWh. Commenters stated if EPA had used Iowa's actual renewable energy generation 

in 2012 to establish its emission reduction goal for 2030, Iowa's goal would have been more 
170

stringent: 1,168 lbs/MWh. Commenters concluded this amounts to a 25% reduction in Iowa's 

current emissions rate. 

Commenters stated in addition to renewable energy development, the proposed regulation 

rewards states that retire coal plants that were in operation in the 2012 baseline year but are then 

retired or converted to natural gas prior to 2020. Commenters stated, Iowa utilities have or are in 

the process of retiring and converting to gas a number of coal units in Iowa that were included in 

the 2012 baseline.

Commenters stated the combination of these coal plant retirements and conversions and the 

proposed methodology with Building Block 3 results in a 2030 emissions rate target that is not 

stringent and a target that Iowa will likely be in compliance with before 2020. Commenters

concluded the EPA could improve the balance between credit for early action and overall 

stringency in the final rule in order to ensure carbon reductions occur in Iowa both prior to 2020 

and between 2020 and 2030.

Comment 151: KS - Goal Format

Response 151: The EPA is finalizing subcategory-specific emission performance rates and ratebased and mass-based statewide goals. See sections VI and VII of the preamble for discussion of 

the subcategory-specific emission performance rates and statewide goals, respectively. .

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

Commenters stated that a rule based on a CO2 rate goal that is based on lbs/MWh is of concern, 

as our Unit is below the lb./MWH goal due to the fact we operate utilizing natural gas.

Comment 152: KS - State goals should be adjusted for an incomplete assumption.

Response 152: See section VI of the final rule preamble of the CPP for a discussion of the 

EPA’s choice of a baseline year. The EPA believes this is a conservative representation of the 

state and regional level emissions and generation values. It recognizes that their will inherently 

be changes to the system infrastructure and operating patterns in the future year (generally 

shifting to a lower emissions intensity scenario), but the EPA took comment on the use of a 

projected baseline versus a historical baseline and commenters generally supported a historical 

baseline. See RTC section 3.1.4 for a discussion of the relationship between heat rate 

improvement and pollution control. EPA also notes that unit-level requirements or assumptions 

are not made in the quantification of BSER, rather region-wide assumptions for the sourcecategory affected fleet.

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

Commenters stated the EPA should adjust the Kansas state goal for an incomplete assumption 

made regarding the commenters' La Cygne Generation Station. Commenters said the EPA 
171

calculated the 2012 baseline based on the historic generation of the station. Commenters stated 

this will not be achieved because of the addition of emission control equipment in 2015 primarily 

required by EPA's Regional Haze Rule. Commenters stated this additional emission control 

equipment will increase the auxiliary loading resulting in a decrease in the net generation at the 

station. Commenters stated Kansas's state goals should be adjusted accordingly.

Comment 153: KS - By including non-dispatchable resources, the EPA has understated the 

CO2 emissions limit that can reliably be met in Kansas.

Response 153: For the EPA’s response to this comment, see the CO2 Emission Performance 

Rate and Goal Computation TSD for CPP Final Rule supporting the final CPP.

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

Commenters stated based on the EPA's formula for determining an emissions limit using the four 

building blocks, there is a bias on the part of the EPA to lower the emissions standard as far as 

possible - beyond standards that result from an adequately demonstrated system. Commenters

said in doing so, the EPA has proposed an emissions standard for Kansas that is too low to 

provide any real options for compliance other than spending an exorbitant amount of money on a 

combination of new NGCC plants, renewable energy, transmission investment, and stranded 

costs. 

Commenters stated the EPA is under the mistaken impression that because the electric grid is 

integrated, electricity is "fungible" and displacement of generation from coal-fired units is an 

easy task. Commenters said what the EPA fails to acknowledge is that the affected coal-fired 

EGUs are base-load units. Commenters stated the U.S. Energy Information Agency defines baseload as follows: 

Base load: The minimum amount of electric power delivered or required over a given period of 

time at a steady rate. 

Base load capacity: The generating equipment normally operated to serve loads on an aroundthe-clock basis. 

Base load plant: A plant, usually housing high-efficiency steam-electric units, which is normally 

operated to take all or part of the minimum load of a system, and which consequently produces 

electricity at an essentially constant rate and runs continuously. These units are operated to 

maximize system mechanical and thermal efficiency and minimize system operating costs. 

Commenters stated by including non-dispatchable resources, such as renewable generation and 

DSM energy efficiency, the EPA has understated the CO2 emissions limit that can reliably be 

met in Kansas. Commenters said while renewable generation certainly has a place in the overall 

generation portfolio of an electric utility, the inclusion of renewable energy must be integrated 

carefully with an eye towards the overall reliability of the grid. Commenters stated, a base-load 

plant provides electricity at an essentially constant rate and runs continuously. Commenters said 
172

obviously, DSM energy efficiency is not a generation resource and cannot under any 

circumstances provide electricity to the grid. 

Comment 154: KS - The EPA's calculation of Kansas's goal for carbon reduction is seriously 

flawed and too low

Response 154: For the EPA’s response to this comment, see the CO2 Emission Performance 

Rate and Goal Computation TSD for CPP Final Rule supporting the final CPP.

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

Commenters stated the EPA's calculation of Kansas's goal for carbon reduction is seriously 

flawed and too low. Commenters said if the EPA issues its final rule on the Clean Power Plan 

and it is in substantially the same form as currently recommended, then it should incorporate the 

following the commenters' organization's revised calculations for the EPA's building blocks in 

determining an appropriate CO2 emissions level.

Commenters reviewed the EPA's calculations setting Kansas's greenhouse gas goal; commenters 

are not conceding agreement with the EPA's building block methodology; and also does not 

claim its review is complete given the limited amount of time allowed to provide comments on 

the proposed plan. Commenters stated however, the technical review results in a significant 

change in the CO2 emission goal assigned to Kansas. Commenters said specifically, the goal 

should be increased from the figure calculated by EPA (1,499 lbs/MWh) to 1,950 lbs/MWh. 

Commenters stated the changes made were to correct for serious flaws within the EPA's 

calculations. 

Commenters stated the purpose of the Clean Power Plan is to "Cut carbon emission from the 

power sector by 30 percent nationwide below 2005 levels" by 2030. Commenters said that the 

seven affected Kansas coal plants identified by the EPA have reduced their combined CO2 

emissions by 19.1% between 2005 and 2012. Commenters said thus, one would expect that 

Kansas has only to reduce CO2 emissions by another 10.9% by 2030. Commenters stated but by 

using a rate approach (lbs./MWh) for calculating Kansas's 2030 goal, the EPA has obviated the 

dramatic improvement Kansas achieved in CO2 reduction from 2005 to 2012. 

Commenters stated Kansas achieved its 19.1% reduction in CO2 between 2005 and 2012 by 

reducing the generation from coal plants and re-dispatching less carbon intensive generation. 

Commenters said between 2005 and 2012, net energy output from affected coal plants declined 

by 17.7% while CO2 emissions declined 19.1%. Commenters stated this large reduction in CO2 

emissions was achieved while Kansas's retail sales of electricity increased by 3.15%. 

Commenters stated by using the rate of CO2 emissions rather than the absolute reduction in CO2 

emissions, EPA shrank the reduction in CO2 emissions in Kansas from 19.1% to just 1.7%. 

Commenters said having stated such, his organization used the same 2012 data for fossil fuel 

sources of electric generation to arrive at a goal of 1,950 lbs/MWh. 
173

Commenters stated a notable disparity in the proposed rule between how renewable energy 

generation is treated for (1) goal setting and (2) for compliance purposes. Commenters said 

specifically for Kansas, when setting the Kansas 2030 goal in step 4b under BSER Block 3, the 

EPA used the 2012 actual state total RE generation of 5,252,653 MWh. Commenters stated of 

that total amount, however, 2,511,888 MWh were not owned by Kansas utilities, and generally 

would not be available to Kansas for meeting its goals under the proposed rule, even while 

counting toward CPP goals in other states. Commenters stated to make up for the inequitable 

treatment of Kansas' renewable generation, his organization proposes that its 2030 goal be 

recalculated by taking the revised regional RE level of 12 percent from above times the Kansas 

utility-owned wind generation. Commenters said note that if a heat rate improvement value of 2 

percent is used in the calculation above (in lieu of the proposed 6 percent, which is unreasonably 

high), the resulting step 4b emission rate becomes 1,912 lbs CO2/MWh. Commenters stated 

further, if no change is made to the proposed rule's value for Kansas demand-side EE avoided 

generation (4,124,018 MWh), the Kansas 2030 CPP goal becomes 1,644lbs CO2/MWh, and 

using an HRI value of 2 percent becomes 1, 712 lbs CO2/MWh. Commenters said this ultimate 

number, 1,712 lbs CO2/MWh, represents the correct value for the Kansas 2030 goal in 

consideration of the factors discussed above, and utilizing the single base year 2012. 

Commenters said in consideration of recommended use of a three-year period (2011 - 2013) to 

set goals, the Kansas 2030 CPP goal (with 6 percent HRI) becomes 1 ,662 lbs CO2/MWh, and 

using an HRI value of 2 percent becomes 1, 732 lbs CO2/MWh.

Comment 155: KS - The EPA did not correctly interpret the applicability of the Kansas 

renewable energy standard and the administrative regulations adopted by the Kansas Corporation 

Commission to implement them

Response 155: The EPA made changes to Nearman Unit 1 and Coffeyville baseline data based 

on comment and further review of the data. See Appendix 1 of CO2 Emission Performance Rate 

and Goal Computation TSD for CPP Final Rule. Section V of the final rule preamble of the CPP 

explains changes made to BB3 and BB4 assumptions for BSER based on comment. Section VI 

of the final rule preamble of the CPP explains the EPA’s choice in baseline year.

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

Commenters stated the EPA did not correctly interpret the applicability of the Kansas renewable 

energy standard and the administrative regulations adopted by the Kansas Corporation 

Commission to implement them. Commenters said the first issue relates to the fact that only 

investor-owned utilities and electric cooperatives are subject to the Kansas RES. Commenters

stated the first bullet below explains the result of this error in interpreting the statute. 

Commenters said the EPA erred in determining the renewable rate to be used for the South 

Central Region average rate. Commenters stated in the proposal, the rate for the entire region 

was determined using the Kansas RES. Commenters said however, Texas' renewable standard 

should be included in developing the regional rate. Commenters stated the second bullet 

describes a corrected South Central Region renewable rate. Commenters said the final issue 

relates to how renewable energy generation is treated for goal setting versus compliance 

purposes. 
174

Use of KS RES for regional RE. Commenters stated in using Kansas's nominal 20% RES for 

fixing the regional RE level at 20%, however, the EPA failed to take into account two factors 

about the Kansas standard: (a) the standard does not apply to all electric utilities in the state, but 

to investor-owned utilities (IOUs) and electric cooperatives only, i.e., not municipal utilities; and 

(b) according to the standard, "[e]ach megawatt of eligible capacity in Kansas installed after 

January 1, 2000, shall count as 1.10 megawatts for purposes of compliance."

Commenters stated noting that the Kansas RES is capacity (peak demand) based, the breakdown 

by energy source owner type for Kansas 2012 EGU capacity, according to correspondence from 

the Kansas Corporation Commission and based on the KCC document at 

http://www.kcc.state.ks.us/pi/2013_electric supply and_dem and report.pdf. 

Commenters said thus, for calculation purposes when used to compare standards among different 

states, the actual (or effective) 2020 RES/RPS used for Kansas should be (20% / 110%) x 

(7,974/8,473) = 17.1%, or 17%. 

Commenters stated Kansas is the only state in the EPA's South Central Region (under the EPA's 

analysis AR, KS, LA, NE, OK, and TX) that has an RES/RPS in percent form. Commenters said 

Texas' standard of 10,000 MW by 2025 was not used by the EPA, apparently because it is 

explicitly capacity-based (i.e., not in percent form), and the proposed rule's "GHG Abatement 

Measures" TSD (http://www2.epa.gov/carbon-pollution-standards/clean-power-planLproposedrule-ghgabatement- measures) states (without further explanation): "EPA did not include targets 

that were capacity-based"-apparently referencing the Database of State Incentives for 

Renewables & Efficiency (DSIRE) website, for example the following text at 

http://www.dsireusa.org/rpsdata/RP5FieldDefinitionsApri12011.pdf: "This [Target Mandate] 

field applies only to states that express their RPS standard in terms of installed capacity (MW). 

At the time of this writing, this, included only TX, IA, and MI." 

Commenters stated about setting RE levels, the same TSD notes: "The EPA compiled the statelevel effective RE levels derived above, organized them by region, and determined an average 

percent generation target for that region. This average did not include any values for states in 

which there is no binding RPS requirement This average regional RE generation target offers a 

basis for the determination of state-level RE targets for informing state goals..." 

Texas RPS. Commenters stated however, the Kansas RES' and other states' standards expressed 

in percent terms are capacity-based, a fact which the EPA overlooked when utilizing the DSIRE 

data. Commenters said therefore, there is no objective reason to exclude Texas' RPS for use in 

finding RE levels. 

Commenters stated for the South Central Region, his organization proposes that the Texas 

standard of 10,000 MW be converted to a percent value, then averaged with Kansas' 17.1 

percent. Commenters said the easiest way to do this (and a conservative way considering growth) 

is to divide the 10,000 MW Texas standard by the state's latest available total generating 

capacity. Commenters stated using the 2012 unit capacity supplied by the EPA at 

http://www2.epa.gov/carbon-pollution-standards/clean-power-plan-proposed-rule description2012-unit-level-data-using, the 2012 total generation capacity for Texas is 148,944 MW. 
175

Commenters said in percent terms, the Texas renewable standard is therefore 10,000 

MWh/148,944 MWh = 6.7%. 

Commenters stated averaged with the effective Kansas RES of 17.1%, the Kansas-proposed RE 

level for the South Central Region should be 11.9%. Commenters said rounded to the nearest 

percent, this is 12%. 

Disparity between how RE treated for goal setting versus compliance. Commenters stated related 

to the last two comments is the notable disparity in the proposed rule between how renewable 

energy generation is treated for (1) goal setting and (2) for compliance purposes. Commenters

said specifically for Kansas, when setting the Kansas 2030 goal in step 4b under BSER Block 3, 

the EPA used the 2012 actual state total RE generation of 5,252,653 MWh. Commenters stated 

of that total amount, however, 2,511,888 MWh were not owned by Kansas utilities, and 

generally would not be available to Kansas for meeting its goals under the proposed rule, even 

while counting toward CPP goals in other states. Commenters stated to make up for the 

inequitable treatment of Kansas' renewable generation, his organization proposes that its 2030 

goal be recalculated by taking the revised regional RE level of 12 percent from above times the 

Kansas utility-owned wind generation as follows: Kansas' RE target = 12% of (2012 total 

electric gen. - non-KS wind gen.) = 0.12 * (44,424,691 - 2,511,888) MWh = 5,029,536 MWh 

Commenters stated thus the recalculated 2030 Kansas goal under step 4b becomes: 4b: CO2 

emission rate = (coal rate * gen.) + (OG steam rate * gen.) + (NGCC rate * gen.) coal gen. + OG 

steam gen. + NGCC gen. + nuclear gen. + renewable gen. = (2,224 x 28,076,795) + (1,466 x 

1,552,435) + 0 lbs CO2/MWh 28,076,795 + 1,552,435 + 0 + 581,272 + 5,029,536 = 1,837 lbs 

CO2/MWh 

Other changes considered. Commenters said note that if a heat rate improvement value of 2 

percent is used in the calculation above (in lieu of the proposed 6 percent, which is unreasonably 

high), the resulting step 4b emission rate becomes 1,912 lbs CO2/MWh. 

Commenters stated further, if no change is made to the proposed rule's value for Kansas demandside EE avoided generation (4,124,018 MWh), the Kansas 2030 CPP goal becomes 1,644 lbs 

CO2/MWh, and using an HRI value of 2 percent becomes 1,712 lbs CO2/MWh. Commenters

said this ultimate number, 1,712 lbs CO2/MWh, represents the correct value for the Kansas 2030 

goal in consideration of the factors discussed above, and utilizing the single base year 2012. 

Commenters stated in consideration of KDHE's recommended use of a three-year period (2011-

2013) to set goals, the Kansas 2030 CPP goal (with 6 percent HRI) becomes 1,662 lbs 

CO2/MWh, and using an HRI value of 2 percent becomes 1,732 lbs CO2/MWh. 

Commenters stated since his organization is recommending that non-Kansas wind be subtracted 

out from total state electric generation to estimate its RE target, the same process should be 

carried out for setting the baseline CO2 emission rate. 

Commenters stated thus the corrected Kansas 2012 baseline CO2 emission rate, after data 

correction and accounting for wind generation owned by non-Kansas entities, comes to 2,088 

lbs/MWh. 
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EPA has overstated EE potential. Commenters said the EPA has substantially overstated the 

amount of EE that could be achieved by states in the future in setting the 111(d) CO2 standards. 

Commenters said the EPA projected increasing levels of EE based on its evaluation of best 

practices, ultimately developing specific goals that increase each state's EE measures by 

approximately 1.5 percent of sales of electricity each year. Commenters stated much of the data 

and methods were developed by EE advocacy 'organizations. Commenters said the metrics 

adopted by the EPA largely incorporate these findings, and differ substantially from the 

engineering-based analyses that have been conducted on the topic. Commenters stated one study, 

conducted by Lawrence Berkeley National Laboratory, reported potential estimates for EE 

savings from 0.5 percent to 1.1 percent. Commenters said several other studies of EE potential, 

conducted mostly by advocacy organizations, EPA consultants, and the EPA's own analysis are 

nearly all "top-down, policy-based approach" studies. Commenters stated only one study 

analyzed by the EPA used a conventional bottom-up engineering approach- a study by the 

Electric Power Research Institute (EPRI) contained in a report that was released in 2009 with an 

update in 2014. Commenters said notably, EPRI's estimate for average annual achievable 

potential was 0.5 percent to 0.6 percent per year. Commenters said ultimately, the EPA chose to 

use 1.5 percent as the best practice level. 

Commenters stated the EPA uses EIA Form 861 data as the baseline level of the amount of EE 

achievements by utility demand-side management programs. Commenters said the EPA 

acknowledges the consistency and quality issues with this data, resulting from the self-reported 

sourcing and different estimation methodologies, but does not address this issue. Commenters

stated while the EPA did use state-specific data from form EIA-861 for establishing starting 

points for EE levels, it applied national estimates of EE potential to this data and applied an EE 

growth rate historically only experienced in other best-practice states. Commenters said the 

applicability of both these metrics has some fundamental flaws, based on the variability of statespecific factors, including relative industrial, commercial, and residential consumption of 

electricity. Commenters stated Kansas is a relatively rural state, with manufacturing mostly 

centered in more populated areas. 

Goal calculation errors and suggested changes. Commenters stated the following comments deal 

with errors made by the EPA in its calculations of Kansas' 2030 goal, as well as steps in the goal 

computation process that his organization recommends EPA take to improve its calculation of 

the Kansas 2030 goal. 

Referring to http://www2. epa. gov/s ites/production/files/2014-06/20140602tsd-plant-level-dataunit-levelinventory 0.xlsx: commenters stated the EPA erred in its allocation of generation and 

emissions data for Riverton Unit 8. Commenters said this unit was converted from coal firing to 

only firing natural gas during 2012, and data for Unit 8 should be edited. 

Referring to http://www2.epa.gov/sites/production/files/2014-06/20140602tsd-plant-level-dataunit-level - inventory 0.xlsx: commenters stated the EPA erred in the value it used for 2012 

electric generation from Coffeyville Unit 4 (i.e., 15,981 MWh). Commenters said the correct 

value is 32,621 MWh. 

Referring to http://www2.epa.gov/sites/production/files/2014-06/20140602tsd-plant-level-dataunit-level - inventory 0.xlsx: commenters stated the EPA erred in the value it used for 2012 CO2 
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emissions from Kansas City Board of Public Utilities Nearman Unit 1 (i.e., 1,465,886.628 tons). 

Commenters said the correct value is 1,475,131.088 tons. 

Referring to http://www2.epa.gov/sites/production/files/2014-06/20140602tsd-egridmethodology 0.xlsx: commenters stated the EPA's value for 2012 Kansas total wind capacity is 

3,170 MW. Commenters said however, the actual value is 2,912 MW, which excludes Waverly 

Wind Farm - that won't come online until 2016 - and two small Westar wind units that have been 

decommissioned. 

RE sold across state lines. Commenters stated the EPA must be consistent in the manner in 

which it treats renewable energy that is sold across state lines. Commenters said when the EPA 

calculated the goals for each state, all renewable megawatt hours (MWh) generated in the state in 

2012 were placed in the denominator. Commenters stated however, with respect to goal 

achievement, if this generation is credited to the power purchaser in a different state, the 

generating state would be required to make up the shortfall. 

2012 baseline. Commenters stated in the proposed Clean Power Plan, the EPA inappropriately 

uses a single-year baseline of 2012. Commenters said a number of events can happen during any 

given one-year period that results in misrepresentation of actual generation and emissions levels. 

Commenters stated factors that should be taken into account include unit operation variances due 

to extreme weather or maintenance, fluctuating natural gas prices, and changes in the types of 

units available for dispatch. Commenters said in Kansas, several large electric generating units 

(EGUs) experienced lengthy outages in 2012 for maintenance and installation of pollution 

control equipment to ensure compliance with other Clean Air Act obligations. Commenters

stated KDHE suggests that using a three-year averaging methodology would smooth out the 

various anomalies and would be more appropriate for setting state CO2 emissions reductions 

goals. 

Commenters stated a three-year baseline period would be consistent with how the EPA expects 

states to demonstrate compliance under the proposed Clean Power Plan. Commenters said as 

currently proposed, the rule would require states to meet the final emission performance level on 

a three-calendar-year rolling average starting January 1, 2030. Commenters stated the EPA even 

states that "[t]he rolling three-year performance periods for measuring actual plan performance 

against the final goal performance level are proposed in light of year-to-year variability in 

economic and other factors, such as weather, that influence power system operation and affect 

EGU CO2 emissions." Commenters stated furthermore, a three-year baseline methodology 

would be consistent with how the EPA has developed and implemented other existing programs 

using multiple years (e.g., Acid Rain Program, Clean Air Interstate Rule, Cross State Air 

Pollution Rule, and permitting and modeling requirements). 

Mass-based goals. Commenters stated the EPA requested comment on whether it should provide 

a presumptive translation of rate-based goals to mass-based goals for all states, for those who 

request it, and/or for multi-state regions. Commenters said the EPA should provide a mass-based 

goal for each state, regardless of whether it is requested, and for multi-state regions upon request. 

Commenters stated further, in the process of setting mass-based goals, the calculations should 

account for projected increase in electrical demand, as a rate-based approach would similarly 

allow for increase in demand. Commenters said finally, the EPA should rely on projected 
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demand as determined by the agency closest to the electrical industry, which, for Kansas, would 

be the Kansas Corporation Commission. Commenters encouraged the EPA to release the rate 

versus mass calculations in the form of a NODA prior to the release of the final rule so states 

would have the opportunity to comment on the calculation and EPA the opportunity to make 

adjustments in the process. 

Gross load vs net load. Commenters stated the EPA requested comment on the use of gross load 

versus net load data for goal compliance. Commenters said Kansas favors the use of gross load 

(i.e., generation) data over net generation for two reasons, consistency and fairness. 

Commenters stated in the document titled "Part of E.O. 12866 and 13563 Review: EPA 

Response to Interagency Comments on the EGU GHG Modified/Reconstructed Source NPRM 

(clean) (2060-AR88) as part of review of EGU GHG Existing Source NPRM (2060-AR33) 

(5/30/2014)" in the docket for the proposed rule, the following text is found: "To the extent that 

the EPA finalizes modified and reconstructed standards for stationary combustion turbines that 

are consistent with the standards for newly constructed stationary combustion turbines, the EPA 

intends to take the same approach with regards to the use of net or gross output in both final 

actions." Commenters said in light of the fact that the EPA's proposed new source CO 2 

standards under section 111(b) are already based on gross generation, for the sake of consistency 

gross generation should also be used for the section 111(d) standards. 

Commenters stated for any state where the proposed rule's goals are to be met on a unit-by-unit 

(or fleet-by-fleet) basis, the use of net generation values penalizes utilities for electricity that is 

used to power pollution control systems - mandated by other EPA regulations - that are installed 

subsequent to 2012. Commenters said additionally, in answer to a question his organization's 

staff asked with regard to affected EGUs using existing EIA forms to report their generation 

under the proposed rule, EPA Region 7 answered: "Kansas will not be using EIA data for 

utilities to show compliance with the 111(d) Plan. The State Plan will need to have monitoring, 

recordkeeping, and reporting, requirements to meet 60.5805. This is also discussed at 79 FR 

34910." Commenters stated KDHE therefore suggests that by using gross generation to meet 

goal performance, affected EGUs, all of which are already Acid Rain sources reporting CEM 

data to the EPA's Air Markets Program, can be relieved of the burden of new reporting 

requirements by simply allowing them use of Air Markets Program (CEM) data to fulfill their 

requirements (for CO2 emissions as well as electric generation) under the proposed rule. 

Credit for early reduction. Commenters stated the EPA requested comment on the option that 

emission reduction effects that occur prior to the beginning of the initial plan performance period 

could be applied toward meeting the required level of emission performance in a state plan, thus, 

enabling a state to count emission improvements achieved by state programs prior to 2020 

toward its interim goal, allowing the state to begin demonstrating emission performance earlier 

and follow a more gradual emission improvement trajectory during the interim performance 

Period of 2020-2029. Commenters said his organization strongly supports this concept as Kansas 

has seen a significant decrease in CO2 emissions for several years prior to the 2012 baseline 

year. 
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Comment 156: KY - Kentucky will have to cut jobs and reliable income, and those less 

fortunate will be hurt by increased utility bills

Response 156: While the EPA expects that there is likely to be additional job loss in sectors 

related to coal attributable to implementation of the CPP, many jobs in this field are expected to 

remain. 

The timeframe of the CPP from plan development to plan implementation allows states, utilities 

and other stakeholders the ability to work together to tailor their plans in the ways that best 

support their communities, so that they can not only reduce their greenhouse gas emissions, but 

also ease the transition of their workforces to the low carbon economy. 

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

Commenters stated the plan is a numbers game masquerading under the guise of allowing 

states flexibility to meet an individual prescribed carbon reduction goal. Commenters added but 

the effect of reaching this goal treats states different and plays favorites. Commenters stated 

Kentucky's assigned target is to reduce carbon emissions in 2013 by 18 percent, while 

Washington State has been assigned a target of over 70 percent.

Commenters stated that the targets paint an illusion by using percentages rather than real 

numbers; an illusion that Kentucky is somehow getting off easy. Commenters added that 

Kentucky will have to cut much more emissions than Washington to meet its target. Commenters

stated that this is because Washington does not utilize low-cost, efficient, and reliable coal fire 

generation and Kentucky does. Commenters stated that Washington will only have to close one 

coal-fired power plant to meet its goal of reducing emissions by over 70 percent. 

Commenters concluded that Kentucky, with 20 coal-fired power plants that provide the state 

with 90 percent of its electricity will have to cut significantly more jobs and reliable income 

for thousands of families across the state in order to meet its goal. Commenters added that it's 

those in less fortunate communities and those who lost their jobs due to fuel switching that are 

hurt the most from higher utility bills.

Comment 157: KY - Additional flexibility regarding schedule is appropriate, but a regional 

approach could significantly lower Kentucky's reduction target.

Response 157: For the EPA’s response to this comment, see the CO2 Emission Performance 

Rate and Goal Computation TSD for CPP Final Rule supporting the final CPP.

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

Commenters stated within the NODA, the EPA claims the concepts for consideration are in 

response to comments from meetings with stakeholders to provide a more fair assessment of 

Building Blocks 2, 3 and 4; changes to the formula for calculating the goal; and more flexibility 

with respect to the timeframe of implementation. Commenters said their organization's review of 

the NODA finds the recommendations regarding the implementation schedule may be more 
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favorable and provide states additional flexibility toward a glide-path approach. Commenters

stated however, the considerations the EPA has outlined relative to the other topics, particularly a 

regional assessment of Building Blocks 2, 3, and 4 could result in significant reductions to 

Kentucky's target emission rate. Commenters stated based on calculations performed by the 

Kentucky Energy and Environment Cabinet, Kentucky's target could change from the original 

proposal of 1,763 lbs CO2/net MWh by 2030 down to as low as approximately 1,034 lbs 

CO2/net MWh, if adopted to the full extent of the potential described in the NODA.

Comment 158: KY - Some options being considered would essentially remove coal-fired 

generation as an important part of the nation's generation mix

Response 158: For the EPA’s response to this comment, see the CO2 Emission Performance 

Rate and Goal Computation TSD for CPP Final Rule supporting the final CPP.

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

Commenters stated while the EPA's proposed state-specific reduction targets for Kentucky and 

other states create compliance challenges for coal-fired generation, some of the options being 

considered by the EPA, as indicated in the NODA, would essentially remove coal-fired 

generation as an important part of the nation's generation mix. Commenters said "levelizing" 

emission reduction targets through a regional approach could substantially increase the hardship 

on coal-reliant states such as Kentucky which is surrounded by states with greater potential for 

renewables, available nuclear capacity, or higher reliance on natural gas. Commenters stated it 

would be inconsistent and irrational for the EPA to evaluate state-specific reduction targets 

deemed achievable by EPA and then proceed to mandate some states go beyond their assigned 

targets and allow others to meet targets significantly below their calculated potential.

Commenters stated in short, most of the NODA alternatives to which the EPA seeks comment 

would result in reduction targets that are largely unachievable by Kentucky without significant 

and concerning implications for the State and electricity customers of his organization.

Commenters stated the Kentucky Energy and Environment Cabinet has determined that under 

some "levelization" scenarios presented with the alternatives in the NODA, Kentucky's reduction 

target could be adjusted as low as 1,034 lbs. CO2/ net MWH. Commenters said reductions of 

such a magnitude would force utilities to prematurely close most of their coal-fired plants in 

Kentucky. Commenters said for every coal-fired generating unit remaining in service, a utility 

would be forced to develop an equivalent amount of renewable energy, a daunting prospect in a 

state like Kentucky with few opportunities to generate energy from renewable sources. 

Commenters stated the vast majority of generating capacity in Kentucky would either move from 

coal to natural gas-fired generation or come from renewable resources imported from other 

states.

Comment 159: KY – RE & EE.
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Response 159: The EPA has revised its block three quantification based on comment. See 

Section V.A. and V.E. of the final rule preamble of the CPP for more information. See section 

V.A. of the final rule preamble of the CPP for the EPA’s response to this comment and more 

information about Building Block 4.

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

Commenters stated EPA should consider that Kentucky has a low potential for renewables, 

which was noted by EPA, and existing Kentucky law bans nuclear plants.

Commenters stated Kentucky has almost met the CO2 reduction requirements required in the 

Clean Power Plan. Commenters added because of the coal-fired power plants that have already 

closed, switched to natural gas, or currently slated to be mothballed before 2020, there is little 

more that Kentucky will have to do to meet the carbon plan's goals.

Commenters concluded that therefore, the Clean Power Plan does not incentivize Kentucky or 

other similar coal-gas-energy-dependent states to move towards sustainable energy development, 

to tap the low-hanging fruit of economic development and savings around energy efficiency, or 

to support demand-side energy efficiency.

Comment 160: KY - The EPA's IPM model assumptions are incorrect with known errors.

Response 160: For the EPA’s response to this comment, see NEEDSv.5.15 file. Also see the 

EPA base case and policy case modeling scenarios for the final rule. EPA notes that unit-level 

projections are illustrative.

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

Commenters stated the EPA's IPM model assumptions are incorrect with known errors. 

Commenters said the model inputs show retirement of the E.W. Brown Units 1 and 2. 

Commenters stated however, KU has no plans or announcements for retirement of these units. 

Commenters said additionally, the model does not show mercury controls for E.W. Brown Unit 

3, Mill Creek Units 1 and 2, or Trimble County Units 1 and 2. Commenters stated although it 

may have a small effect, negative energy for KU's Tyrone Station in the 2012 actual data used 

for the goal calculation should be excluded because Tyrone did not operate in 2012.

Commenters stated other questionable retirements just within Kentucky include TVA Shawnee, 

Big Rivers Electric Corporation's Reid Unit 1, and the Cooper and Dale Stations owned by East 

Kentucky Power. Commenters said the model also incorrectly shows continued operation of the 

Paradise Coal Units 1 and 2.

Commenters stated a related limitation of IPM is that this model does not represent unit 

commitment and electric power plant hourly dispatch in a detailed manner. Commenters said 

research that EPRI has done shows that important insights can be gained when electric sector 

models capture positive and negative correlations between load, renewable energy resource 

variability, and uncertainty across adjacent regions given that renewable resources are non-
182

uniformly distributed in space and time. Commenters stated the EPA should consider enhancing 

the treatment of renewable energy in IPM and to complement the IPM analyses with more 

detailed, unit commitment modeling.

Comment 161: LA - The EPA erroneously calculated Louisiana's goal - suggested changes 

provided

Response 161: The EPA has made a number of changes to its baseline data in the final rule that 

incorporate the data corrections identified by commenters. Notably, it is using net summertime 

capacity, treating the Ninemile point and Morgan City facilities mentioned as under construction, 

has re-categorized Perryville power Station unit 2-ct, re-categorized the units at Louisiana 1, and 

removed Washington Parish Energy Center from its list of under construction units.

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

Commenters claimed EPA erroneously calculated LA's goal, and provided changes.

Commenters stated that EPA erroneously estimated the capacity of Louisiana's NGCC fleet, 

resulting in unfairly stringent emission limits for Louisiana.

Commenters stated that if the Agency insists on retaining the current building-block approach, 

EPA should, at a minimum, make the following changes to the calculation of Louisiana's 

emission reduction goals: 

Use net capacity not nameplate. Commenters stated that while EPA used name plate capacity of 

NGCC units in the emission limit calculation, EPA uses capacity information from the National 

Electric Data System (NEEDS) in the IPM modeling. Commenters added that unit capacity 

values in the NEEDS v.5.13 data base reflect net summer dependable capacity, which is more 

often used in daily planning and operation purposes during the summer peak season, after 

accounting for auxiliary services. Commenters stated that the NEEDS v5.13 net summer ratings 

should be used in the emission limit calculation in building block 2 instead of EIA nameplate 

capacity. 

Several NGCC were omitted. Commenters stated that several NGCC units under construction in 

Louisiana were not included in the calculations. Commenters expounded that Units 6a and 6b at 

Entergy Louisiana Nine Mile Point have nameplate capacity of 640 MW and projected net 

summer capacity of 559 MW. Commenters noted that also, Louisiana Energy and Power 

Authority's (LEPA) Morgan City Power Plant NGCC unit 14-01 is under construction and will 

have a nameplate capacity of 84 MW and projected net summer capacity of 64.5 MW. 

Perryville NGCCs. Commenters stated that EPA's emission limit calculations for Louisiana 

classify each of the three gas turbines at Entergy Louisiana's Perryville Power Station as NGCC 

units. Commenters noted that however, one of the three, unit ID 2-CT, is not equipped with a 

heat recovery steam generator and operates in simple cycle mode only. Commenters concluded 

that therefore, the capacity for that unit should not be included in the block 2 equation. 
183

Entergy Gulf State No. 1 plant. Commenters stated that EPA's calculations include input data for 

five EGUs at Entergy Gulf States Louisiana's Station No. 1 Generating Plant. Three of the units, 

(1A, 2a and 3A) are boilers and not turbines. Commenters stated that no unit at Louisiana 1 will 

meet the definition of affected electric generating unit because none of these units supplies onethird or more of its potential electric output and more than 219,000 MWh net-electric output to a 

utility distribution system (Information source Initial comments of Louisiana Department of 

Environmental Quality RE: 40 CFR 60 Subpart UUUU-Carbon Pollution Emission Guidelines 

for Existing Stationary Sources: Electric Utility Generating Units(79 FR 34830), September 12th 

2014,). Commenters concluded that input data for these units should be removed from the 

building block 2 calculations. 

Washington Parish Energy Center. Commenters noted that EPA's calculations include input data 

from Washington Parish Energy Center which is neither in operation nor under-construction. 

Commenters concluded that upon making the above adjustments to the input data for block 2 of 

the emission limit calculations, Louisiana's final emission limit goal should be 1,078 lb/MWh 

and the alternate limit should be 1,239 lb/MWh.

Comment 162: LA - The EPA should remove R.S. Nelson Units 1A and 2A from calculations 

as they are not affected units

Response 162: Per the commenters’ indication, the EPA has re-categorized R S Nelson 

Generators 1A and 2A to “EXCLUDE” in the baseline inventory and is not treating them as 

likely affected units. However, the EPA notes this does not constitute a final applicability 

determination.

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

Commenters requested EPA remove R.S. Nelson Units 1A and 2A from the state's calculation; 

these are not affected units.

Commenters stated that EPA included efficiency improvements for R. S. Nelson Units 1A and 

2A (Westlake, Louisiana) in setting the state goal for Louisiana in Building Block 1. 

Commenters added that these units are operated by Entergy, but are owned by Nelson Industrial 

Steam Company. Commenters described that the units were constructed for the purpose of 

supplying electrical power and steam to chemical plants and refineries owned by Nelson 

Industrial Steam Company, and the units do not supply one-third or more of their potential 

electric output to a utility distribution system on a three-year rolling average basis. Commenters

concluded that these units, therefore, are not "affected units," as defined by the Proposed Rule, 

and should be removed from the state's calculation.

Comment 163: LA - The EPA should re-evaluate its model because Brame Energy Center Unit 

2 will not be retired
184

Response 163: For the EPA’s response to this comment, see the EPA base case and policy case 

projections for the final CPP Rule. EPA unit-level projections are illustrative and not 

prescriptive of a compliance requirement.

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

Commenters stated EPA's IPM model erroneously predicts the retirement of Brame Energy 

Center Unit 2 in year 2016 and requests EPA re-evaluate its model to include the expected costs 

of the proposed BSER and ensure that its proposed targets for Louisiana take into account the 

continued operation of the unit.

Commenters stated that a review of the files from the Integrated Planning Model (IPM) results 

reveals that data for Cleco's Brame Energy Center Unit 2 (previously referred to as Rodemacher 

2) is not included in the year 2016 or for any other year thereafter. Commenters stated that this 

suggests EPA's model assumes that Cleco will retire the unit. 

Commenters added that in response to Cleco's inquiry regarding this discovery, EPA's Power 

Sector Modeling staff indicated that the assumed retirement of Unit 2 was most likely 

attributable to the NEEDS data base, which may indicate an expected retirement of the unit in 

year 2016. Commenters stated that however, Cleco's own predictive modeling of demand and 

optimum generation indicates that Unit 2 is expected to operate normally in year 2016 and Cleco 

does not expect to retire the unit in the near future.

Comment 164: LA - The EPA has misapplied and/or miscalculated at least three of the 

Building Blocks as they apply to the state of Louisiana

Response 164: For the EPA’s response to this comment, see the CO2 Emission Performance 

Rate and Goal Computation TSD for CPP Final Rule supporting the final CPP. In addition to 

updating its BSER quantification, EPA has also updated unit-level data for EGUs in Louisianna 

that impact its state’s goal.

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

Commenters stated as the Agency is well aware, the EPA's greenhouse gas (GHG) goals for 

Louisiana are 948 lbs/MWh in 2020 (a reduction of 35.3% from the 1,466 lbs/MWh rate 

recorded in 2012) and 883 lbs/MWh in 2030 (a reduction of 39.8%). Commenters said these 

goals were ostensibly developed using the four "Building Blocks" proposed by the EPA. 

Commenters stated it is LUS' firm belief, however, that the EPA has misapplied and/or 

miscalculated at least three of these Building Blocks as they apply to the state of Louisiana, and 

more particularly to LUS' Brame (Rademacher) Unit 2 (hereafter referred to as RPS-2). 

Commenters said in addition, the unit retirements and dispatch adjustments proposed by the EPA 

are impractical in the timeframe allowed.
185

Comment 165: LA - There are errors and omissions in the data used to calculate Louisiana's 

state goal

Response 165: For the EPA’s response to this comment, see the CO2 Emission Performance 

Rate and Goal Computation TSD for CPP Final Rule supporting the final CPP.

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

Commenters opposed the EPA's proposed rule because it unequivocally exceeds the authority 

provided to EPA by Section 111(d) of the Clean Air Act, and risks undermining Louisiana’s

economic development while providing questionable and unsubstantiated environmental benefit. 

Commenters said the proposed rule sets Louisiana's final goal at 883 pounds of CO2 per net 

megawatt hour (lb CO2/MWh) and specifies the state's "alternate goal" as 1025 lb CO2/MWh. 

Commenters stated after accounting for the discrepancies identified herein, Louisiana's final goal 

should be 1078 lb CO2/MWh, with an alternate goal of 1239 lb CO2/MWh. Commenters said 

while the EPA's use of this incorrect data calls into question the rule in its entirety and warrants 

its abandonment, at the very least the EPA should revise Louisiana's goals; however, even if 

these numbers are revised by EPA- the results would still cripple Louisiana’s economy.

Comment 166: LA - The EPA's proposed BSER for Louisiana is discriminatory

Response 166: See section I.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:

LA targets. Commenters stated the 2020 Interim Goal will require Louisiana to reduce its CO2 

emissions by 38 percent from a baseline level of 1,533 lbs/MWh to 948 lbs/MWh. Commenters

stated the EPA's 2030 Final Goal of 883 lbs/MWh is a 42 percent reduction relative to the EPA's 

2012 baseline. Commenters said overall, the Interim Goal will require Louisiana to reduce its 

power sector CO2 emission by as much as 17.8 million metric tons, and 19.7 million metric tons 

by 2030. Commenters stated the EPA's proposed final CO2 emissions reductions is comparable, 

in level terms (or mass balance terms) to the carbon emissions of three of Louisiana's four major 

coal facilities (Brame Energy Center, Dolet Hills, and RS Nelson).

LA reductions relative to other states. Commenters stated Louisiana will be required to reduce its 

CO2 emissions at a level comparable to the national average reduction under the proposed CPP. 

Commenters identified Louisiana's required emissions reductions relative to other states despite 

the fact that Louisiana uses about 27 percent more natural gas to generate electricity than the 

overall U.S. average.

Commenters stated Louisiana gets effectively no credit, under the proposed CPP, for having 

spent decades concentrating its power generation resources into cleaner burned fuel sources.

Commenters said Louisiana will be required to reduce its CO2 emissions by 650 lbs/MWh, an 

amount virtually equal to the national average of 649 lbs/MWh.
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Commenters identified the inequity of the proposed EPA CPP in greater detail. Commenters

stated in 2012, 16 states reported that they generate 80 percent or more of their electricity from 

coal. Commenters said of those 16 states, only one (South Dakota) has a proposed CPP carbon 

emissions reduction that is greater than the national average (67 percent reduction). Commenters

stated another four states have reductions that are comparable to the national average, while the 

balance are below, and in some instances, well below the national average and the required 

reductions the EPA is imposing on Louisiana. Commenters stated consider that four states 

(Kentucky, North Dakota, Wyoming, and West Virginia) all report 100 percent of their power 

being generated from coal, and yet all four have emissions reductions less than 30 percent.

LA emission reductions as share of GDP. Commenters stated even more imposing is the impact 

that the proposed CPP will have on Louisiana ratepayers. Commenters said Louisiana's required 

emissions reductions, as a share of state Gross Domestic Product (or "GDP") is considerable. 

Commenters stated that Louisiana will be one of the hardest impacted states on an emissions 

reduction per GDP basis of any state in the country. Commenters said Louisiana, for instance, 

ranks 8th in the required reductions per unit of state GDP under the proposed CPP.

Various components of BSER for LA. Commenters said Building Block 1, which estimates the 

percent reductions available from improved coal plant thermal efficiencies, accounts for 8 

percent of Louisiana's required CO2 reductions under the proposed CPP. Commenters stated 

Building Block 2, which estimates the CO2 reductions that would arise if Louisiana required its 

natural gas combined cycle ("NGCC") units to increase their operating utilization rates to 70 

percent on an annual average basis, accounts for the overwhelming share (58 percent) of the 

reduction under the EPA's BSER estimates for Louisiana. Building Block 3a, representing the 

emissions reductions associated with preserving "at-risk" nuclear generation, accounts for three 

percent of Louisiana's BSER. Commenters said Building Block 3b, estimated to be the potential 

emission reductions available from the utilization of greater levels of renewable energy, would 

account for 16 percent of Louisiana's BSER. Commenters stated lastly, Building Block 4, 

estimated by the EPA as the potential CO2 reductions that could arise from greater levels of 

energy efficiency, are estimated to account for 15 percent of Louisiana's BSER.

Overall issues. Commenters stated take serious issue with the development of the EPA's BSER, 

in general, and the methods by which each of the building blocks associated with the BSER are 

calculated. Commenters said there are errors associated with each of the analyses that leads to 

significant overestimates of the potential emissions reductions available in each of the building 

blocks. Commenters stated further, the EPA has failed to consider other critical policy issues in 

estimating Louisiana's BSER such as cost and power system reliability.

Comment 167: LA - The EPA should work with each state to correct its factual errors and 

develop realistic CO2 emission standards, if the rule is finalized

Response 167: The EPA reviewed and incorporated many State comments into the CPP Final 

Rule. The corrected factual errors identified by the Louisiana Department of Environmental 

Quality can be identified in the unit-level data on Appendix 1 of the CO2 Emission Performance 

Rate and Goal Computation TSD for CPP Final Rule supporting the final CPP.
187

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

Commenters stated that the states have expressed significant concerns with the final emission 

performance goals. Commenters said about Louisiana - On September 12, 2014 the Louisiana 

Department of Environmental Quality (LDEQ) submitted comments to the EPA expressing 

serious concerns on Louisiana's final goal of 883 pounds of CO2 per net megawatt hour. 

Commenters said LDEQ points out in their letter that the EPA made factual errors in the 

proposal by classifying certain combustion sources as Natural Gas Combined Cycle (NGCC), 

but these sources are actually simple cycle units or are a boiler. Commenters stated LDEQ also 

points out that the EPA again factually erred in believing that construction was completed on a 

permitted energy center. Commenters said LDEQ's comments concludes that, after correcting the 

EPA's factual errors using EPA's methods, Louisiana's final goal should be 1,078 lb CO2/MWh.

Commenters stated in summary, the EPA should work with each state to correct its factual errors 

and develop realistic CO2 emission standards, if the rule is finalized.

Comment 168: ME - By lumping bioenergy with all other renewables, and biomass and wasteburning as if they reduce emissions as effectively as wind and solar, the EPA may be 

inadvertently promoting these technologies as mitigation measures

Response 168: 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.2.c and Section VIII.K.1 of the preamble.

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

Commenters stated by lumping bioenergy with all other renewables, and biomass and wasteburning as if they reduce emissions as effectively as wind and solar, the EPA may be 

inadvertently promoting these technologies as mitigation measures in the GHG rule. 

Commenters said further, counting these emissions as zero can also introduce significant errors 

into the estimate of present day power sector CO2 emissions and target emissions rates, which 

are likely to be carried forward as states attempt to meet target emissions goals. Commenters

stated this problem is most apparent for those states where bioenergy and waste-burning 

contribute a significant share of total CO2 emissions. 

Commenters said to explore this further, the same data as the EPA was used, from the Agency's 

Emissions and Generation Resource Integrated Database (eGRID), to estimate what proportion 

of state-level GHG emissions were not being included in the EPA's official totals. Commenters

said for the initial estimation of 2012 baseline power sector rates, the EPA only considers power 

generation and emissions from a segment of the total power sector, excluding facility emissions 
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from contributing to calculated 2012 state-level emissions rates on various grounds. Commenters

stated standalone biomass plants and municipal waste combustors are excluded because they are 

"non fossil fuel" units, burning less than 10% fossil fuels. Commenters stated the EPA also 

excludes industrial/commercial power generators that are not connected to the grid, a set of 

facilities that includes a substantial number of biomass-burning units. Commenters said simple 

cycle turbine plants less than 25 MW and steam turbine plants less than 25 MW/250 MMBtu are 

also excluded. 

Commenters said emissions from biomass- or waste-burning facilities were excluded from state 

totals on the basis of being non-fossil fueled (states with low amounts of biomass/waste in this 

category may nonetheless have biomass/waste burning units that were excluded on the basis of 

not being connected to the grid).

Commenters stated Florida is the state with the most bioenergy/waste emissions excluded from 

its 2012 emissions total (13.2 million tons). Commenters said in terms of how CO2 from 

biomass and waste burning compares to reported CO2 from fossil fuels on a percentage basis, 

Vermont is the leader, but in fact biomass energy does not actually provide a high percentage of 

the power generated in that state, due to the presence of the 543 MW Vermont Yankee nuclear 

plant. 

Commenters stated that Maine is the state where biomass makes the largest percentage 

contribution to both in-state power generation and power sector CO2 emissions. Commenters

said some of Maine's 2012 emissions as reported in eGRID were not included in the EPA's 

summed total.

Commenters stated in Maine, four fossil-fueled plants contribute the 17% of emissions initially 

regulated by the GHG rule. Commenters said of the excluded emissions, Rumford Cogeneration 

(a biomass-burning plant owned by NewPage Corporation), contributes 1.3 million tons of CO2, 

13% of eGRID's reported emissions for the state. Commenters said another 28% of reported 

emissions are contributed by facilities burning biomass and waste where emissions have not been 

included in the total because they occur at facilities burning less than 10% fossil fuels (these are 

the "standalone" biomass and waste-burning plants). Commenters stated biomass/waste burners 

that are not connected to the grid, and are therefore not included in the EPA total, contribute a 

further 17% of emissions; similarly, 12% of emissions come from fossil-fueled plants not 

connected to the grid. Commenters said another 25% of emissions come from fossil-fueled 

facilities excluded because they are less than 25 MW in size. Commenters stated not reported at 

all to eGRID are those facilities that burn fuels solely for thermal energy. 

Comment 169: ME - The EPA's decision to exclude new biomass power development from its 

forward-looking modeling reflects some realities about costs and impacts of biomass energy

Response 169: 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.
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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.2.c and Section VIII.K.1 of the preamble.

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

Commenters stated the EPA's decision to exclude new biomass power development from its 

forward-looking modeling is obviously not prescriptive, but it does reflect some realities about 

costs and impacts of biomass energy. 

EPA's modeling counts biomass energy emissions

Commenters said first, the EPA has counted actual stack emissions from bioenergy in its 

forward-looking modeling, which probably explains in part why little new bioenergy capacity is 

included, since growing the industry is counterproductive to reducing emissions. Commenters

said the modeling treats biomass but as a high-carbon fuel with emissions of 195 lb 

CO2/MMBtu, a rate that translates approximately one ton of forest wood emitting one ton of CO2

when burned (the modeling still treats biogenic waste burning as having zero emissions.) 

Commenters stated under this scheme, any net reductions in lifecycle CO2 emissions that do 

occur over time are a "bonus" - but the model doesn't depend on them occurring in its 

determination of how states can meet their target goals. Commenters stated this is a sound 

modeling decision, for while it means that the modeling does not match EPA's equation for 

determining state-level goal emissions rates, it is useful because it answers the questions, "What 

happens if under EPA's carbon accounting framework, or due to legal reasons, all bioenergy 

emissions must be counted? Can states still achieve their renewable energy goals with minimal 

bioenergy?"

Commenters stated in Maine, as elsewhere, the answer is yes, with the modeling projecting a 

mixture of low-emissions renewable energy, natural gas, and high-emissions biomass to help the 

state to achieve its 2030 emissions goal. 

Commenters said under the modeling scenario for Maine, biomass provides the majority of the 

state's power sector CO2 emissions in 2030 (while the modeling treats biogenic municipal waste 

burning as zero emissions, the contribution of waste burning to the total mix is low). 

Commenters stated the modeling does contain some flawed assumptions, and only covers a 

relatively small portion of the state's power sector. Commenters stated however, the fact that 

bioenergy-heavy Maine can achieve the emissions goals even while constraining new bioenergy 

development and counting full stack emissions from existing plants is a rebuttal to biomass 

industry arguments that new bioenergy build out is necessary for achieving renewable energy 

goals. 

Commenters stated at the same time, the large percentage of biomass burners that is excluded 

from regulation shows how little the existing industry has to fear from the GHG rule, at least in 

Maine.

Commenters said the biomass industry has always been careful to avoid the 250 MMBtu fossilfuel limit, to avoid regulation as fossil-fueled plants under other EPA rules. Commenters stated 
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these include the NSPS set for particulate matter emissions at fossil-fueled electric utility boilers, 

and the triggering provisions for Prevention of Significant Deterioration permitting (whereby if a 

boiler receives more than 250 MMBtu heat input from fossil fuels, it is regulated as a fossilfueled unit where PSD permitting is triggered by emissions of 100 tons of a criteria pollutant, 

rather than the 250 tons of emissions that trigger PSD permitting at biomass-fueled boilers). 

Commenters said similarly, most biomass- burning plants are exempted from regulation under 

the GHG rule because they don't receive more than 250 MMBtu heat input from fossil fuels, or

because they are commercial/industrial units that are not connected to the grid. Commenters

stated giving the existing biomass industry even less cause for concern about the rule, EPA's 

modeling demonstrates that even biomass-heavy Maine can achieve its emissions reduction 

target while counting emissions from ongoing operation of existing biomass facilities. 

Comment 170: ME - The Proposed Rule Incorrectly Identifies Wyman Station as an Affected 

EGU

Response 170: The EPA still views William F Wyman as a likely affected source and it is 

included in the baseline. However, as discussed in section V and VI of the final rule preamble of 

the CPP, the EPA has switched from a state-specific to a region-specific approach to determine 

subcategory rates. In its BSER application, it assesses the reduction potential across the fleet and 

recognizes that every source is unique and will have different constraints in which it operates. 

The EPA’s BSER quantification does not make any unit-level requirements or assumptions, but 

rather assess the region’s fleet potential at the aggregate level. The comment does not provide 

any demonstration that this unit does not meet the 111(d) applicability criteria, so it is still 

included as part of the baseline of “likely affected units”.

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

Commenters stated the proposed rule identifies Wyman Station as an affected EGU. 

Commenters said because Wyman Station is oil-fired, Maine's goal is calculated based in part on 

the assumption that the electrical generation from Wyman Station can be replaced by increasing 

utilization of the three NGCC units considered by the EPA to be affected EGUs in the proposed 

rule, thereby reducing CO2 emissions. Commenters stated this is not a plausible scenario 

because Wyman Station is a spinning reserve facility that only generates electricity when called 

upon to do so by ISO-New England when other EGUs in the region, including the 

aforementioned NGCC units, cannot generate enough electricity to meet demand. Commenters

said the most likely scenario in which FPL would be called upon to operate Wyman Station is 

when the supply of natural gas in the region is not sufficient for the NGCCs in the region to 

generate adequate electricity to meet demand. Commenters stated under this circumstance, it is 

not possible to replace Wyman Station's generation with NGCC generation, since the reason 

Wyman Station operates is because there is insufficient fuel to operate the NGCC plants.

Commenters stated the EPA must re-calculate Maine's baseline and target emission rates without 

including Wyman Station as an affected EGU.
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Comment 171: ME - The EPA must re-calculate Maine's baseline rate and target rate of CO2 

emissions based on consideration of Westbrook Station as Maine's only affected EGU

Response 171: For the EPA’s response to this comment, see the CO2 Emission Performance 

Rate and Goal Computation TSD for CPP Final Rule supporting the final CPP. EPA notes that 

its final inventory of likely affected units does not constitute an applicability determination. 

EPA. See section VII.E of the preamble for a discussion of the relationship between state goals 

and EGU status change.

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

Commenters stated the EPA calculated Maine's baseline emissions rate in a framework that 

includes four affected EGUs, including three NGCC plants that qualify as existing EGUs under 

the language in the proposed rule. Commenters said these plants all meet or exceed the CO2 

emission standards in the EPA's proposed NSPS, and if they were to be built or modified in 

2016, they would be exempt from consideration as affected EGUs under the rule as proposed. 

Commenters said in order for Maine to achieve the goal proposed in the rule, these plants will be 

required to operate more efficiently than they would be if they were new plants. Commenters

stated this is illogical and far from cost-effective. Commenters said it makes no sense to require 

an older source to meet more stringent standards than a new source. Commenters stated Maine 

recommends that the EPA modify the proposed rule to exempt EGUs that either already meet, or 

are modified to meet the CO2 emission standards being proposed for new fossil fuel-fired EGUs 

under the NSPS. Commenters said in states or regions with existing NGCC capacity and 

significant steam capacity, this will create greater latitude for redispatch away from higheremitting steam EGUs and may encourage retirement of these facilities. Commenters said the 

EPA has proposed that four EGUs in Maine should be considered to be affected EGUs under the 

rule as proposed: FPL Energy Wyman LLC in Yarmouth (Wyman Station); Westbrook Energy 

Center in Westbrook (Westbrook Energy); Rumford Power Company in Rumford (Rumford 

Power); and Maine Independence Station in Veazie (Maine Independence). Commenters said 

Appendix D to the EPA's Technical Support Document (TSD) for Goal Computation provides 

the 2012 output in MWh for each of these four plants. Commenters stated Wyman Station has a 

potential output of 850 MW, or 7A46,000 MWh/year, and sold 59,067 MWh in 2012, which 

represents 0.8% of potential output; Westbrook Energy has a potential output of 552 MW, or 

4,835,520 MWh/year, and sold 2A46,083 MWh in 2012, which is 50.6% of potential output; 

Rumford Power has a potential output of 251 MW, or 2,198,760 MWh/year, and sold 363J95 

MWh in 2012, which is 16.5% of potential output; and Maine Independence has a potential 

output of 520 MW, or 4,555,200 MWh/year, and sold 1,243,500 MWh in 2012, which is 27.3% 

of potential output. Commenters said Wyman Station operates as "spinning reserve", and only 

supplies electricity to the grid when Maine's other assets cannot meet demand. Commenters

stated the EPA should exempt Wyman Station from the proposed rule, because it supplies far 

less than one third of its potential output to the grid, and it operates at the minimum level 

necessary to function as an emergency reserve. Commenters stated Rumford Power and Maine 

Independence also supply significantly less than one third of their potential output to the grid, 

and should therefore not be considered affected EGUs under the proposed rule. Commenters said 

the EPA should re-calculate Maine's baseline CO2 emission rate and target CO2 emission rate 

based on Westbrook Energy as Maine's only affected EGU.
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Commenters stated Maine and other states in the Northeast are exploring ways to increase the 

availability of natural gas in New England, and are hopeful that a plan can be put in place that 

will resolve the natural gas shortages and associated price spikes that have plagued the region in 

recent years. Commenters said if the Northeast region is able to solve the regional natural gas 

shortage, Maine's NGCC units may actually increase power generation well beyond current 

levels of operation. Commenters stated it is possible that in future years one or more of these 

EGUs will exceed the 1/3 sales threshold and thereby potentially qualify as affected EGUs at that 

time. Commenters said the proposed rule does not address the possibility that EGUs may be 

subject to regulation for less than the entire compliance period. Commenters stated it is not 

possible to know in advance when or if one or more potentially affected EGUs will actually 

become affected under the proposed rule. Commenters said the final rule should define EGUs as 

affected based upon their status at the time the rule is adopted, using generation, sales and fuel 

use data from the three years immediately preceding adoption. Commenters stated this will 

enable states to create compliance plans based on concrete information rather than speculation 

regarding future generation characteristics, and will avoid states being required to dedicate 

scarce resources to continually modifying their compliance plan. Commenters said for the same 

reasons, EGUs that change their operational characteristics during the proposed rule's 

compliance period, increasing generation to such an extent that they would have been considered 

affected EGUs at the time the rule was adopted, should be subject to the NSPS proposed under 

Section 111(b) of the CAA.

Commenters stated the EPA must re-calculate Maine's baseline rate and target rate of CO2 

emissions based on consideration of Westbrook Station as Maine's only affected EGU. 

Commenters said the EPA must also add provisions to the proposed rule that make non-affected 

EGUs exempt from regulation under the proposed rule, and require them to meet the NSPS in the 

event that future operations cause them to exceed the minimum threshold criteria of affected 

EGUs.

Comment 172: ME - The EPA must exempt EGUs that are not connected to the US grid from 

consideration under the proposed rule

Response 172: See section VIII.K. of the final rule preamble of the CPP for the EPA’s response 

to this comment. Also see the applicability language in section IV.D. 

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

Commenters stated the EPA must exempt EGUs that are not connected to the US grid from 

consideration under the proposed rule.

Commenters stated Maine is unique in that it borders on only one other state, with most of its 

political boundaries adjoining Canada. Commenters said because of this physical isolation, 

significant parts of Maine are connected to the Canadian grid and not under the control of USbased distribution networks. Commenters stated it is not realistic to expect Maine to develop a 

compliance plan that requires a Canadian company, operating in Canada, to act in a particular 

way. Commenters said the final rule needs to clearly exempt those parts of states that have no 
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interconnection with the US grid. Commenters stated the proposed rule has no provision to 

account for electricity distribution that is beyond a state's control. Commenters said Maine urges 

the EPA to exempt EGUs in that are solely connected to the Canadian grid from the final 

compliance rates.

Commenters stated the EPA must exempt EGUs that are not connected to the US grid from 

consideration under the proposed rule.

Comment 173: MI - NGCC emission rates used to set state goals under BB2 are unreasonable; 

should use rates equal to proposed standards for new units when setting goals for existing units

Response 173: See section V.D. of the final rule preamble of the CPP for the EPA’s response to 

this comment and more information about Building Block 2. EPA no longer relies on useful 

thermal output when quantifying BSER. Therefore, the NGCC rates assumed in the calculation 

no longer reflect useful thermal output and are consequently higher in the final CPP than the 

proposed CPP for the state of Michigan of 998 lb/MWh.

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

Commenters said that in its calculation of emission rate targets for Michigan, the EPA uses a 

state specific average NGCC emission rate of 810 lb/MWh, which is incorrect and misrepresents 

actual achievable emissions. Commenters requested that EPA use reasonable NGCC emission 

rates in setting the goals for building block 2. Commenters said a review of the available data for 

existing NGCC units in Michigan indicates that the EPA used thermal heat output in addition to 

electric generation output from combined cycle plants in the calculation of the average CO2 

emission rate for Michigan. Commenters said the use of thermal heat output in this calculation is 

incorrect; the calculation should only include electric generation output. Commenters said taking 

out the thermal heat output yields 998 lb/MWh as the average of NGCC net electric generation 

emission in Michigan, which is a more reasonable emission factor for calculating the state goal 

for building block 2.

Commenters said in addition, emissions associated with ramping up NGCC units to higher 

capacity factors should be weighted towards units with more potential generation, not the 

average for all NGCCs. Commenters said the more efficient NGCCs should have lower emission 

rates and also higher baseline utilization. 

Commenters said that for most states, the average NGCC emission rate is below the proposed 

standards for natural gas-fired stationary combustion units that EPA is requiring for new or 

modified and reconstructed sources under Sec. 111(b). Commenters said these unreasonable and 

unrepresentative state average emission rates cause state goals to be more stringent than what 

would be required if EPA's proposed standards for new or modified and reconstructed sources 

were used in the goal setting calculation. Commenters said to avoid the differences among unit 

capabilities and emissions in each state, and to avoid inconsistencies between thermal and 

electric generation output, they recommend the use of NGCC emission rates for setting emission 

rate goals that are equivalent to EPA's proposed standards for new, modified or reconstructed 
194

units [1,000 lb CO2/MWh gross for larger units (>850 mmBtu/hr), 1,100 lb CO2/MWh gross for 

smaller units (<850 mmBtu/hr)].

Comment 174: MI - Request the final 2030 target for Michigan to be amended

Response 174: For the EPA’s response to this comment, see the CO2 Emission Performance 

Rate and Goal Computation TSD for CPP Final Rule supporting the final CPP.

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

Commenters requested the final 2030 target for MI be amended.

Commenters stated the final 2030 target for Michigan must be subsequently amended in the final 

rule. Commenters stated that when entered into EPA's state goal calculation spreadsheet for 

Michigan, a target of 1,442 lbs CO2/MWh is derived.

Commenters added that additional modifications to the target will also be needed to account for 

Ludington and base year changes as requested.

Comment 175: MI - Three different goal numbers were developed for Michigan

Response 175: There was one final goal rate for Michigan at Proposal – 1,161 lb/MWh. See 

page 22 at http://www2.epa.gov/sites/production/files/2014-06/documents/20140602tsd-goalcomputation.pdf. Please see section VII of the final rule preamble for rate-based and mass-based 

statewide goals for Michigan.

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

Commenters noted that in the calculation of the state goals there are three different goal numbers 

developed for Michigan in terms of percent reduction in the proposal and technical support 

documents (TSD): 31.5 percent, based on the adjusted rate in the preamble, 36 percent based on 

the numbers in the Goal Computation TSD, and 45 percent calculated from the initial to the final 

number in the Regulatory Impact Analysis (RIA) modeling.

Comment 176: MI - Corrections for 2012 renewable energy generation in Michigan

Response 176: For the EPA’s response to this comment, see the CO2 Emission Performance 

Rate and Goal Computation TSD for CPP Final Rule supporting the final CPP.

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

Commenters offered corrections for 2012 renewable energy generation.
195

Commenters stated that in review of the building block calculations for Michigan, it was noted

that EPA data assumptions, utilizing EIA state-level renewable energy generation on existing 

Renewable Energy for Michigan should be corrected as follows for 2012 Renewable Energy 

generation:

1. Plant Operator Name: Invenergy

Plant Name: Gratiot County Wind

2012 Net Generation (MWh): 226,178

Correction: The 2012 generation from this source needs to be included in the total for 

Michigan

2. Plant Operator Name: Sumpter Energy Associates

Plant Name: City Sand

2012 Net Generation (MWh): 9,993

Correction: Missing from EPA 2012 Calculations

3. Plant Operator Name: Sumpter Energy Associates

Plant Name: Carleton Farms Phase I

2012 Net Generation (MWh): 42,428

Correction: Missing from EPA 2012 Calculations

4. Plant Operator Name: Sumpter Energy Associates

Plant Name: Carleton Farms Phase II

2012 Net Generation (MWh): 33,730

Correction: Missing from EPA 2012 Calculations

5. Plant Operator Name: Wayne Energy

Plant Name: Wayne Energy

2012 Net Generation (MWh): 4,026

Correction: Missing from EPA 2012 Calculations

Comment 177: MI - Concern that the proposed final state goal for Michigan is more stringent 

than other similarly situated Midwestern states

Response 177: See section I.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 stated the proposed final state goal for Michigan is more stringent than other 

similarly situated Midwestern states. Commenters said Michigan's final goal of 1,161 average 

pounds of CO2 per net MWh is lower than those of Illinois (1,271), Indiana (1,531), and Ohio 

(1,338). Commenters stated requiring a lower rate from Michigan, a state that has already made 

significant progress in reducing carbon emissions, is inequitable.
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Comment 178: MN - General comments and Building Block 1

Response 178: See section V.C. of the final rule preamble of the CPP for the EPA’s response to 

this comment and more information about Building Block 1.

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

General Comments

Commenters stated that their comments to EPA's electric utility sector greenhouse gas emission 

reduction proposals have been shared under various submittals for over 2 years (e.g. since EPA's 

April of 2012 proposed new unit NSPS proposal). Commenters said that throughout all this time, 

they have consistently expressed concerns that the EPA's proposals for reducing Minnesota 

electric generation related greenhouse gas emissions are targeting emissions standards or 

proposed targets with stringency that is technically unworkable or not cost effectively achievable 

relative to the cost effectiveness criteria relevant for or applicable to the electric utility sector in 

Minnesota and our region. 

Commenters said that the EPA has inadequately recognized Minnesota early action that reduces 

CO2 emissions from electricity generation when determining Minnesota BSER building 

block targets. Commenters said that Minnesota legislators, regulators and utilities have already 

implemented early measures similar to the EPA's BSER strategies, and indicated these measures 

were deployed while applying cost effectiveness criteria pertinent to Minnesota utilities and 

electricity customers. Commenters indicated that full recognition of Minnesota early action 

would accept ongoing Minnesota initiatives as adequate for satisfying the EPA's Clean Power 

Plan target assigned to Minnesota through 2030.

Building Block 1 Comments

Commenters stated that cost effective early deployment of turbine generator efficiency 

improvements on Minnesota coal units have already been implemented, delivering the 

greenhouse gas emission reductions from Minnesota coal generating units under early action that 

EPA is now proposing for the CPP. Commenters said that these improvements were made after 

determinations by Minnesota regulators that the projects were cost effective, as part of utilities' 

resource planning or rate recovery proceedings. 

Commenters explained that the Minnesota Public Utilities Commission (MPUC) has required 

Minnesota utilities to adopt heat rate improvement projects and maintenance practices that 

optimize the balance between preserving unit operating efficiency and dispatch capability. 

Commenters said that these measures help preserve the dispatch capability of an electric 

generating unit, which helps assure that the value of generation resources is retained over time, 

as utility, customer and energy market needs continue to evolve. Commenters said that integrated 

resource planning, regulated by the MPUC, is part of what guides the process for deployment of 

new resources and dispatch capability of existing generation resources.

Credit should be given for early action. Commenters said that in determining the 6% Block 1 

target for improving coal unit efficiency, the EPA used calendar year 2012 reported generation, 

which effectively "books" the already optimized Minnesota generating unit efficiency measures 
197

into 2012 generation statistics, without giving recognition or CPP credit for cost effective 

generating unit efficiency improvements implemented before 2012. Commenters said thus, the 

EPA's target-setting component under its CPP Block 1 is redundant to Minnesota early action 

measures. Commenters stated that the EPA's Block 1 target should recognize Minnesota's early 

actions as satisfying Block 1 target compliance for Minnesota.

A 6% HRI is not reasonable for smaller generating units. Commenters indicated that a 6% heat 

rate improvement target is not reasonable for smaller generating units. Commenters said that this 

is both a consequence of how small units don't carry the economy of scale that helps keep cost 

per unit of electricity output affordable, and due to the manufacturers of heat rate improvement 

equipment not offering "off the shelf" components for small units. Commenters indicated that 

customizing equipment to accommodate small unit-specific requirements adds to cost, if such 

equipment is available at all.

Sargent and Lundy Report. Commenters said it is notable that the report prepared by Sargent 

and Lundy (S&L Coal-Fired Power Plant Heat Rate Reductions, Final Report SL-009597, 

Project 12301-001, January 22, 2009, the "S&L Report") from which the EPA identified 

potential Block 1 generating unit efficiency options, referenced in the EPA's CPP Block 1 

Technical Support Documentation, pre- dates deployment of the turbine upgrades that improved 

heat rate performance of Minnesota Power units. Commenters said the S&L analysis cites some 

of the very measures deployed by Minnesota Power among those it suggests for efficiency 

improvements, just as the report also recognized that variances between units preclude the 

deployment of all measures identified by S&L on all electric generating units. 

Minnesota already meeting BB1 target. Commenters said if the EPA recognized Minnesota 

early action since 2005, including measures such as generation heat rate improvement programs 

and deployment of measures recognized in the above-referenced S&L Report, Minnesota would 

be found to already have delivered on the EPA's Block 1 target measures. Commenters said 

consequently, the EPA should accept Minnesota early action for generating unit efficiency 

improvements as sufficient for fully satisfying the EPA's proposed CPP Block 1 target. 

Commenters said that because the CO2 emissions per net megawatt hour from coal units posted 

in 2012 already includes the benefit of these early deployed efficiency improvements in 

Minnesota, the EPA should eliminate that six percent component from the CPP target set for 

Minnesota. Commenters added that these Minnesota actions, taken early and voluntarily, should 

receive the EPA CPP compliance "extra credit" for their improved environmental performance, 

years ahead of the EPA's proposed actions.

Comment 179: MN - Building Block 2 related comments

Response 179: See section V.D. of the final rule preamble of the CPP for the EPA’s response to 

this comment and more information about Building Block 2.

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

Commenters stated that the EPA has incorrectly assumed that a national "one-size-fits-all" 

opportunity for re-dispatching existing natural gas combined cycle units (NGCC) is possible or 
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viable. Commenters stated that the EPA's Block 2 usurps Minnesota regulatory authority over 

Minnesota electricity resource planning and cost recovery and should be eliminated from the 

Clean Power Plan (CPP).

Commenters said that Minnesota's integrated resource planning (IRP) process already optimizes 

generation resources, giving balanced consideration to customer need, economics over the long 

term, fuel supplies costs and risks, socioeconomic impacts, and managing risks and 

environmental stewardship, including CO2 emission environmental externalities. Commenters

said Minnesota's resource mix, as reflected by power supply makeup of each of its utilities, 

includes significant and increasing amounts of intermittent renewable resources, and said the 

resulting energy mix of dispatchable capacity from Minnesota's existing coal and NGCC units is 

necessary to preserve grid integrity and customer service reliability. Commenters said these 

comprehensive IRP measures better serve the EPA's indicated intent of its CPP than the EPA's 

"one-size-fits-all Block 2 targeted, but artificial, dispatch level for existing NGCC. 

Commenters said there is little uncommitted dispatch opportunity existing for Minnesota NGCC 

units to accommodate the EPA's CPP assignment of a 70% capacity factor level of operation.

Commenters said this Minnesota resource availability situation is in conflict with what the EPA 

assumes would be available for re-dispatch from all existing NGCC electric utility units 

nationwide. Commenters said the EPA should correct this oversight by eliminating the Block 2 

coal to natural gas re-dispatching contribution when setting the Minnesota CPP BSER target and 

should recognize Minnesota's robust integrated resource planning process as sufficient for 

satisfying BSER Block 2. 

Commenters indicated that the Minnesota Department of Commerce and Minnesota Public 

Utilities Commission have provided for implementation of a mature integrated resource planning 

and engineering review process. Commenters explained that Minnesota utilities propose 

measures for meeting customer electricity needs and cost recovery for resource deployment and 

operation that balances the economics, reliability, environmental performance and 

socioeconomic impacts while managing risk, consistent with state law. Commenters said these 

IRP measures include significant public stakeholder input and are subject to a transparent, 

robust, measured and just regulatory process. Commenters said they are designed to deliver 

universally available, least cost supply of reliable electricity to Minnesotans. Commenters said 

over the years the IRP process has provided for the deployment of electric generation including 

provisions for recent and ongoing deployment of environmental control retrofits on fossil units 

as reviewed and recommended by the Minnesota Pollution Control Agency (MPCA). 

Commenters said this Minnesota regulator review includes analysis of whether environmental 

measures are cost effective through determination of economic break points above which further 

action is assessed as uneconomic (i.e., deployment of measures through the "heel of the cost 

curve"). Commenters added that the economic analysis includes consideration of environmental 

emission externality costs, including those for CO2, PM, SO2 and NOx. 

Commenters said that in addition, Minnesota IRPs and Minnesota Public Utility Commission 

cost recovery approvals consider the dispatch at which these generating resources would be 

economic. Commenters said consequently, the balance of existing NGCC and coal-fueled 

generation in Minnesota reflects NGCC dispatch that provides for reliability under conditions of 

increasing use of intermittent renewable energy resources and for serving customer peak 
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electricity generation needs. Commenters said in contrast, the EPA's Block 2 analysis arbitrarily 

attempts to re-dispatch existing NGCC, presuming a 70% capacity factor level that could only be 

achieved while serving as a base load resource. Commenters said that since these Minnesota 

existing NGCC units were deployed for different purposes and to serve different dispatch needs 

than base load service, it is not appropriate to presume such re-dispatch. 

Commenters said that if the EPA insists on including NGCC re-dispatch in Minnesota's CPP 

target, the EPA must consider the measures and costs that would be incurred to replace the 

intermittent renewable resource reliability, peak power generation resource service electric and 

natural gas transmission support that the NGCC units currently provide. Commenters said these 

considerations would be in addition to what EPA has recognized will be needed to bolster 

infrastructure, to support the EPA's arbitrary 70% target set for existing NGCC units, annual 

capacity factor. Commenters said that historic operation of Minnesota existing NGCC units has 

more typically run in the 10% to 25% capacity factor range. Commenters said that the EPA notes 

an average 24.5% capacity factor for Minnesota existing NGCC units in 2012, a year that 

experienced unprecedented low natural gas prices that are not currently available nor would be 

commercially expected into the future.

Comment 180: MN - The EPA's treatment of generation resources within state boundaries can 

create taking of rights

Response 180: See section VIII.L. 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's approach for determining state-by-state CPP targets ignores 

ownership rights in generating resources. Commenters said state targets were established by 

considering generating resources within a state and electricity customer retail sales in the state, 

but actual sourcing of electricity to service those sales may come from both within and outside 

the state borders. Commenters said electric utilities may own or operate electric generating 

resources in one state that may or may not serve electricity customers in that state. Commenters

said joint ownership, assignment and long term sales are commonplace in the electric industry,

due to the high capital cost, long lived assets and economy of scale benefits larger assets offer. 

Commenters said that by allocating the renewable attributes of a generating resource to a state, 

regardless of whether the owner of the generating resource resides in that state or uses the 

generation to serve customers in that state, EPA has effected an unlawful taking of property 

rights. 

Commenters said for example, renewable generation constructed in North Dakota to help meet 

the Minnesota state mandated RPS is counted toward North Dakota renewable energy goals in 

the EPA's Technical Support Documentation. Commenters said when the EPA established the 

Minnesota and North Dakota CPP target portion for BSER Block 3 renewables, the EPA 

referenced each state's retail electricity sales and assigned a percentage for qualifying renewable 

energy. Commenters said in turn, the EPA 15% renewables target was established by the EPA 
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analysis based on the average RPS for states in the region with an RPS. Commenters said 

however, CPP state renewables BSER targets may also include state approved RPS qualifying 

renewable energy options (such as existing hydro) that the EPA is proposing will not be 

recognized for CPP proposed compliance. Commenters said consequently, the relative stringency 

of a CPP renewables target set in a state is affected by considering both renewables deployed in 

other regions that qualify for satisfying a state RPS and renewables that EPA has not determined 

will count for CPP compliance. Commenters said thus, the EPA's use of state borders for 

determining renewable resource responsibility creates situations where resources deployed and 

paid for on behalf of electric utility customers in one state may have their underlying renewable 

energy value attributed to another state. 

Commenters indicated that Power Purchase Agreements (PPAs) commonly used to provide for 

renewable energy resource delivery to satisfy state renewable energy targets may also put 

electricity customers at risk of disaggregation from the benefits of renewable energy resources 

for which electricity customers have been paying when renewal is due. Commenters said PPAs 

expire and may or may not be up for renewal at timing when the capital investment serviced by 

satisfaction of a state renewable energy standard is still under cost recovery. 

Commenters recommended that any asset or power purchase agreement that is recognized, 

approved and paid for by utility customers be given credit when accounting for CPP compliance. 

Commenters said that in the case of Minnesota Power, its significant North Dakota wind 

investments, PPAs and Canadian Hydro PPAs should be included and credited towards 

Minnesota compliance with the EPA's Clean Power Plan, as Minnesota Power has prudently 

developed these resources to capitalize on the economics, economies of scale, strong 

partnerships and strategic linear infrastructure (such as AC and DC transmission lines).

Comment 181: MN - State should decide credit and treatment of existing hydro for CPP credit 

as RE

Response 181: 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 existing hydroelectric generation should receive full Clean Power Plan 

(CPP) credit as a renewable energy resource so that hydro generation has equivalent standing to 

other renewable energy resources for CPP compliance.

Commenters stated said they have Minnesota-based hydroelectric plants that count toward 

achievement of the Minnesota Renewable Portfolio Standard that, in turn, the EPA has 

considered as part of Block 3 target setting under the CPP. Commenters said the state of 

Minnesota also imports about ten percent of its electricity from Canadian existing hydroelectric 

generation resources that may or may not satisfy current state renewable energy requirements, 

but may be allowed to satisfy future renewable energy requirements. Commenters said the EPA 

should give deference to the state to decide credit and treatment of existing hydroelectric power 

for satisfying state CPP targets. Commenters said Minnesota Integrated Resource Planning 
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already includes consideration of available existing and proposed new generation resources, 

conservation and energy efficiency measures. Commenters said the EPA's insertion of 

constraints on states for CPP compliance that does not recognize the environmental attributes of 

hydro generation can create problems with takings of property rights from parties who own or 

are under agreement to receive the output from generation resources in approved state Integrated 

Resource Plans and state rate-making filings. 

Comment 182: MN - Renewables built by Minnesota ratepayers that are located outside of 

Minnesota should be credited to Minnesota; the rule should address this issue and establish a 

way to resolve state conflicts

Response 182: See section VIII.L. of the final rule preamble of the CPP for the EPA’s response 

to this comment. EPA has regionalized building block three, and not included any existing RE in 

the BSER quantification or state goals.

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

Commenters stated that another huge concern we have is the location of the renewable 

generation that rate payers of Minnesota have already developed. Commenters added that a large 

percent of the wind generation that Minnesota utilities have built resides in optimum locations 

but is outside the borders of Minnesota; primarily in the Dakotas, Wyoming, and Iowa.

Commenters stated that this renewable generation was built by Minnesota rate payers to meet the 

requirements of the Minnesota Renewable Energy Standard and should be credited to 

Minnesota's CO2 reductions under this proposal.

Commenters concluded that Minnesota state officials have received preliminary confirmation 

from the EPA that this will count for Minnesota, but the final rule will need to address this issue, 

along with a way to resolve state by state conflicts.

Comment 183: MN - Target requirements should be both physically and economically available 

for deployment on unit

Response 183: See section V.C. of the final rule preamble of the CPP for the EPA’s response to 

this comment and more information about Building Block 1.

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

Commenters indicated that the EPA's assigned stringency to existing electric generating unit 

CO2 emissions should not extend beyond measures that are physically and economically 

available for deployment on the unit. 

Commenters said that the EPA established the Block 1 generating unit efficiency improvement 

targets for Minnesota and neighboring states at 6%, considering statistical analysis of heat rate 
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improvements achieved during maintenance outages and by referencing a Sargent and Lundy 

study of plant efficiency improvement options. Commenters recommended that states be allowed 

to hear petitions from utilities for accepting a unit as delivering adequate heat rate performance, 

giving consideration to cost effective deployment of heat rate improvement measures. 

Commenters said upon state approval of the unit's petition, the state's target would be adjusted to 

reflect the change in the state's Block 1 stringency such that other units are not compelled to 

provide for additional efficiency measures. Commenters said absent a means for giving relief to 

state target-setting when individual units demonstrate they cannot cost effectively meet a 6% 

efficiency improvement, the EPA's CPP target-setting process would be compelling units owned 

or operated by different utilities to outlay additional funds to compensate for the EPA BSER cost 

effectiveness or feasibility assessment errors.

Comment 184: MN - Minnesota technical corrections submitted to the EPA

Response 184: For the EPA’s response to this comment, see the CO2 Emission Performance 

Rate and Goal Computation TSD for CPP Final Rule supporting the final CPP.

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

Commenters stated the Minnesota Pollution Control Agency (MPCA) submitted to the EPA 

technical corrections related to the EPA characterization of the Best System of Emission 

Reduction CPP target set for Minnesota. Commenters said the EPA should apply these 

corrections as consideration is also given to Minnesota early action measures, making 

adjustments in the EPA CPP targets for Minnesota and providing for Minnesota utility source 

CPP compliance. 

Comment 185: MN - Hutchinson Plant #2 is not an affected unit and must be removed from 

calculations

Response 185: The EPA reviewed the Hutchinson Plant 2 data and still considers generators 2 

and 3 to be likely affected units in the EPA’s baseline inventory. The EPA believes nearly all 

non-cogeneration NGCC units greater than 25 MW will be subject to the CPP applicability 

criteria. However, as explained in the preamble, the baseline inventory does not constitute a 

final applicability determination. See section VII.E for further discussion on applicability status 

and relationship with state goals adjustments.

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

Commenters stated that the NGCC capacity for MN in the EPA calculation must be revised to 

remove Hutchinson Plant #2-ORIS 6358-Generators 2 and 3. Commenters said Hutchinson Plant 

#2 does not meet the criteria of an affected unit because its average annual operation has been 

below 219,000 MWh. Commenters said these units have never operated at or above this 

threshold, and these units should be removed from the EPA's list of affected sources.
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Comment 186: MN - The EPA's CPP provisions should not impede the deployment of effective 

and ongoing state programs

Response 186: For the EPA’s response to this comment, see section VIII of the final rule.

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

Commenters emphasized that the EPA should encourage proactive, environmentally friendly 

programs under deployment in states. Commenters said for example, Minnesota Power is 

implementing the EnergyForward strategy, which was part of Minnesota's Integrated Resource 

Plan (IRP) process. Commenters said EnergyForward is an effective and balanced response to 

transition our generation fleet away from a mix of about 95% coal and 5% renewables in 2005 

towards a balanced mix of one third each of renewable energy, natural gas and coal-fueled 

electric generation. Commenters stated customer conservation improvements and energy 

efficiency programs are also a key component of our EnergyForward strategy. Commenters said 

the EPA's CPP provisions should not impede the deployment of effective and ongoing state 

programs of this nature. 

Comment 187: MN - Ongoing concerns about the EPA greenhouse gas emission reduction 

proposals stringency, cost and the EPA's overlooking significant Minnesota early action benefits.

Response 187: See sections V.C. VI.D., VIII.B, and VIII.C. of the final rule preamble of the 

CPP for the EPA’s response to this comment. Also see section 3.1.4 of the RTC for a discussion 

on heat rate improvement and pollution controls. EPA does not assume any specific unit make a 

heat rate improvements, its quantification of BSER is premised on what is achievable at the 

source-category fleet level on average.

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

Commenters stated comments to EPA's electric utility sector greenhouse gas emission reduction 

proposals have been under preparation and shared under various submittals for over 2 years (e.g. 

since the EPA's April of 2012 proposed new unit NSPS proposal). Commenters consistently 

expressed concerns that the EPA's proposals for reducing Minnesota electric generation related 

greenhouse gas emissions are targeting emissions standards or proposed targets with stringency 

that is technically unworkable or not cost effectively achievable relative to the cost effectiveness 

criteria relevant for or applicable to the electric utility sector in Minnesota and the region. 

Commenters suggested some key areas in which the EPA should modify their proposal before 

finalization that can address these concerns: the EPA has inadequately recognized Minnesota 

early action that reduces CO2 emissions from electricity generation serving Minnesota electricity 

customers when assigning the Minnesota Best System of Emission Reduction (BSER) "Block" 

targets. Commenters stated Minnesota legislators, regulators and utilities have already 

implemented early measures similar to EPA's Best System of Emission Reduction (BSER) 

activities for reducing Minnesota electric utility greenhouse gas emissions. Commenters stated 

these Minnesota measures were deployed while applying cost effectiveness criteria pertinent to 
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Minnesota utilities and electricity customers. Commenters said full recognition of Minnesota 

early action would accept ongoing Minnesota initiatives as adequate for satisfying EPA's Clean 

Power Plan target assigned to Minnesota through 2030 as outlined below. Commenters said

Minnesota's legislators, regulators and utilities already have the policy, regulation and action 

plans in place, without additional EPA regulation, that are responsive and wholly adequate in 

providing the affordable, environmentally sound and reliable electric service Minnesota residents 

and businesses require and deserve.

a. Generation energy efficiency improvements (BSER Block 1).

Commenters stated cost effective early deployment of turbine generator efficiency improvements 

on Minnesota coal units have already been implemented, delivering the greenhouse gas emission 

reductions from Minnesota coal generating units under early action that the EPA is now 

proposing for the CPP. Commenters said these improvements were made after determinations by 

Minnesota regulators that the projects were cost effective, as part of utilities' resource planning 

or rate recovery proceedings. 

Commenters stated the Minnesota Public Utilities Commission (MPUC) has required Minnesota 

utilities to adopt heat rate improvement projects and maintenance practices that optimize the 

balance between preserving unit operating efficiency and dispatch capability. Commenters said 

these measures help preserve the dispatch capability of an electric generating unit. Commenters

stated preservation of dispatch capability helps assure that the value of generation resources is 

retained over time, as utility, customer and energy market needs continue to evolve. Commenters

said integrated resource planning, regulated by the MPUC, is part of what guides the process for 

deployment of new resources and dispatch capability of existing generation resources.

Commenters stated in determining the 6% Block 1 target for improving coal unit efficiency, the 

EPA used calendar year 2012 reported generation. Commenters said use of a 2012 baseline 

effectively "books" the already optimized Minnesota generating unit efficiency measures into 

2012 generation statistics, without giving recognition or CPP credit for cost effective generating 

unit efficiency improvements implemented before 2012. Commenters said for example, in 2009 

and 2010 Minnesota Power's Boswell Energy Center Units 3 and 4, the two largest generating 

units, representing more than 50% of Minnesota Power's nameplate generating capability for its 

system, underwent turbine replacements, achieving improvements in gross plant efficiency of 

5% and 8.7% respectively. Commenters stated other Minnesota utilities have implemented 

similar turbine efficiency improvements (e.g. Xcel Energy's Sherco Unit 3). Commenters said 

thus, the EPA's target-setting component under its CPP Block 1 is redundant to Minnesota early 

action measures. Commenters stated the EPA's Block 1 target should recognize Minnesota's 

early actions as satisfying Block 1 target compliance for Minnesota.

Commenters stated a 6% heat rate improvement target is not reasonable for smaller generating 

units. Commenters said this is both a consequence of how small units don't carry the economy of 

scale that helps keep cost per unit of electricity output affordable and due to the manufacturers of 

heat rate improvement equipment not offering "off the shelf" components for small units. 

Commenters stated customizing equipment to accommodate small unit-specific requirements 

adds to cost, if such equipment is available at all.
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Commenters stated it is notable that the report prepared by Sargent and Lundy (S&L Coal-Fired 

Power Plant Heat Rate Reductions, Final Report SL-009597, Project 12301-001, January 22, 

2009, the "Sargent and Lundy Report") from which the EPA identified potential Block 1 

generating unit efficiency options, referenced in the EPA's CPP Block 1 Technical Support 

Documentation, pre-dates deployment of the turbine upgrades that improved heat rate 

performance of Minnesota Power units. Commenters said the S&L analysis cites some of the 

very measures deployed by MP among those it suggests for efficiency improvements, just as the 

report also recognized that variances between units preclude the deployment of all measures 

identified by S&L on all electric generating units. 

Commenters stated were the EPA to recognize Minnesota early action since 2005, including 

measures such as generation heat rate improvement programs and deployment of measures 

recognized in the Sargent and Lundy Report, Minnesota would be found to already have 

delivered on EPA's Block 1 target measures. Commenters said consequently, the EPA should 

accept Minnesota early action for generating unit efficiency improvements as sufficient for fully 

satisfying the EPA's proposed CPP Block 1 target. Commenters stated because the CO2 

emissions per net megawatt hour from coal units posted in 2012 already includes the benefit of 

these early deployed efficiency improvements in Minnesota, the EPA should eliminate that six 

percent component from the CPP target set for Minnesota. Commenters stated additionally, these 

Minnesota actions, taken early and voluntarily, should receive the EPA CPP compliance "extra 

credit" for their improved environmental performance, years ahead of the EPA's proposed 

actions. Commenters said they also serve as reinforcement to his organization's comment that the 

EPA's proposed regulations in Block 1 are unnecessary and redundant to early and ongoing 

Minnesota measures.

Comment 188: MN - Should use actual capacity for Mankato Energy, rather than nameplate

Response 188: The EPA has switched its assessment of NGCC generation to rely on the summer 

capacity metric as described in preamble section V.A.4.b of the final rule preamble of the CPP 

and the EPA has updated the summer capacity value for Mankato in its 2012 unit-level file 

informing the baseline.

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

Commenters requested that the actual capacity of the Mankato Energy (ORIS 56104) unit be 

used rather than the name plate capacity. Commenters said that Mankato Energy has a current 

capacity of a maximum of 375 MW at 6 degrees F. Commenters said the name plate capacity 

reported to EIA of 530 MW is due to the large capacity of the unit's steam turbine, if the facility 

had been constructed with all components [it was not]. Commenters said at this time, the steam 

turbine portion is oversized as the facility has only one combustion turbine and one heat recovery 

steam generator (HRSG).

Commenters said that the actual capacity of 375 MW is made up of 295 MW of combined cycle 

output with 80 MW of peaking power developed in the HRSG by employing duct burners. 

Commenters stated that the existing Mankato Energy Center consists of one Siemens 501FD 
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combustion turbine generator, one Nooter/Erikson HRSG, a Toshiba TCDF 40L steam turbine 

generator, and other ancillary equipment. Commenters stated in order to be able to generate up to 

530 MW of power as the name plate capacity states, additional components must be installed at 

the unit. Commenters stated that because the plant was, and continues to be physically unable to 

generate 530 MW, the EPA should revise its presumption of the potential generation capacity for 

this unit to 375 MW

Comment 189: MN - The EPA should not use presume or default assumptions when 

determining Minnesota CPP targets

Response 189: See section V.D. of the final rule preamble of the CPP for the EPA’s response to 

this comment and more information about Building Block 2 and see the CO2 Emission 

Performance Rate and Goal Computation TSD for CPP Final Rule supporting the final CPP for 

goals.

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

Commenters strongly requested the EPA to not use presumed or default assumptions when 

determining Minnesota CPP targets.

Commenters stated the EPA made a series of assumptions about Minnesota electric utility 

generation and customer electricity service when assigning a Minnesota proposed Best System of 

Emission Reduction target emission rate. 

Commenters stated as clearly indicated in the EPA's CPP proposal, the nature and extent of 

Minnesota early action did not receive proper credit in the EPA target setting. Commenters said 

for example, when the EPA set Minnesota's Block 2 related target contribution for switching 

from existing coal generation to existing natural gas combined cycle (NGCC) generation, the 

EPA incorrectly presumed how existing NGCC capacity might be available to reassign for 

dispatch at a 70% capacity factor average for the state.

Commenters stated Minnesota Public Utility Commission oversight and the IRP process consider 

what resources are deployed and how the resources are dispatched in order to meet: Minnesota's 

needs for regional voltage support, reliability for accommodating the ongoing Minnesota build 

out of intermittent renewable energy resources, service for energy intensive industry needing 

affordable, 24/7 electricity and support of the Minneapolis/St. Paul peaking electricity resource 

needs. 

Commenters stated Minnesota participates in the Midwest Independent System Operator (MISO) 

system, which ensures delivery of least-cost dispatch and reliable electricity service to Minnesota 

retail electricity customers. Commenters said moreover, Minnesota's strong history of regulation 

keeps Minnesota electricity service as affordable, reliable and environmentally responsible as 

possible.

Commenters stated the EPA's presumption that Minnesota existing NGCC can replace 

Minnesota existing coal resources, thereby delivering higher cost natural gas services throughout 
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the state, ignores Minnesota's carefully managed resource balance without providing 

consideration of the price and reliability consequences to all Minnesota customers. 

Comment 190: MN - Sherco Unit 3 was offline in 2012

Response 190: See section VI of the final rule preamble of the CPP for a response to this

comment. The EPA performed a nationwide evaluation on the significance of unit-level outages 

with respects to state level data. It has adjusted the baseline up for the state in this case to reflect 

the outage.

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

Commenters indicated that the baseline calculation for 2012 for Minnesota must be 

corrected. Commenters stated Sherburne County Generating Station (Sherco) Unit 3 was offline 

for all of 2012 due to an unplanned outage, making the starting point of Minnesota's goal 

calculation atypical. The commenters said the calculation should be corrected as this 

approximately 900 MW unit will be operating for the duration of the planning period and likely 

beyond.

Comment 191: MN - Sherco 3, the EPA's Heat Rate Improvement Targets in Building Block 1 

Are Unattainable

Response 191: See section V.C. of the final rule preamble of the CPP for the EPA’s response to 

this comment and chapter 2 of the GHG Mitigation Measures TSD supporting the final CPP for 

more information about Building Block 1.

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

Commenters stated the heat rate improvements contemplated in Building Block 1 are not 

technically feasible for his organization because of previous improvements made to Sherco 3. 

Commenters said in the case of Sherco 3, the heat rate improvements contemplated by Building 

Block 1 are not technically feasible because Sherco 3 is a more recently constructed plant, and 

SMMPA and Xcel have already made extensive emissions and efficiency improvements to the 

unit.

Commenters stated, Sherco 3 is a highly efficient generator that has been equipped with state-ofthe-art emissions control technology. Commenters said at the time it was built, environmental 

controls accounted for roughly 30% of the $1.072 billion construction budget. Commenters

stated as of August 2010, $391,009,587 in emissions controls for Sherco 3 have already been 

invested. Commenters said the unit's boiler was equipped with low nitrogen oxide burners and an 

overfire air system for NOx emissions control to limit the formation of nitrous oxides. 

Commenters stated the unit was also equipped with state-of-the-art control systems for sulfur 

dioxide and particulates, and the unit has sorbent injection system to control mercury emissions.
208

Commenters stated further considerable resources to reduce Sherco 3's carbon emissions have 

been expended. Commenters said in 2011, Sherco 3 underwent a major retrofit of the 

intermediate and high pressure turbine sections to improve efficiency. Commenters stated this 

upgrade cost $21 million. Commenters said indeed, Sherco 3 has already made or is planning to 

make most of the efficiency improvements contemplated by the EPA under Building Block 1.

Commenters stated given these prior and planned improvements, it will not be technically 

feasible to achieve an additional 6% reduction for Sherco 3 through further heat-rate 

improvements. Commenters said this reality presents practical and financial challenges. 

Commenters said considerable resources in making improvements to Sherco 3 were invested 

with the expectation that the unit will run in the long term. Commenters estimated that Sherco 3 

has an additional useful life of 30 years and has debt financing on the unit that it will be 

servicing until at least 2028. Commenters said thus, to the extent the Proposed Rule limits 

Sherco 3's ability to operate, it would greatly increase costs because not only would servicing 

the debt for the prior investments in the unit have to be continued, purchase replacement power 

to offset the reduction in Sherco 3's operations would also occur. Commenters urged the EPA to 

ensure that Building Block 1 will account for the technical feasibility of the contemplated 

improvements for individual units.

Comment 192: MN - Minnesota Baseline Corrections

Response 192: See section VI of the final rule preamble of the CPP for a response to this 

comment. The EPA has adjusted the baseline up for the state in this case to reflect the outage. 

The EPA has also adjusted the capacity for Mankato facility. It currently still considers the 

Hutchinson units referenced as likely affected units.

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

Commenters stated on September 16, 2014, the Minnesota Pollution Control Agency ("MPCA") 

submitted a letter to the EPA in Docket ID No. EPA-HQ-OAR-2013-0602 addressing certain 

technical issues that affect calculation of baseline emissions used to establish emissions 

reduction goals for Minnesota. Commenters said in that letter, MPCA requested certain 

corrections to electric generating unit status and characteristics used to calculate Minnesota's 

goals, specifically addressing Northern States Power Minnesota Sherburne County Unit 3 

("Sherco 3"), Mankato Energy, and Hutchinson Plant #2. Commenters stated with respect to 

Sherco 3, the 938 MW coal-fired generating unit was out of service during the entire calendar 

year of 2012. Commenters said this was an unusual condition and does not reflect Minnesota's 

current and anticipated future reliance on this unit. Commenters stated thus, as MPCA requests, 

Minnesota's 2012 baseline conditions should be recalculated to include generation at Sherco 3. 

Commenters stated with respect to Mankato Energy, the presumed potential generation capacity 

of this unit should reflect its current capacity of 375 MW. Commenters said finally, as MPCA 

describes, Hutchinson Plant #2 generators 2 and 3 should be removed from the EPA's list of 

affected sources because they do not meet the criteria for affected units and Minnesota's natural 

gas combined cycle capacity should also be adjusted to remove this plant.
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Comment 193: MN - Credit for New Hydro Power

Response 193: 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 the EPA has not been clear on the role of hydropower in counting toward 

state compliance with the goals. Commenters said however, because such hydropower is carbon 

free and will further reduce the need for new coal power, it should count toward compliance with 

Minnesota's goal. Commenters stated for example, Minnesota Power is planning on bringing a 

significant amount of new hydropower from Canada to its generation mix in the next decade, 

with hydro ultimately producing 10 to 15 percent of Minnesota Power's overall generation 

source. Commenters stated Minnesota ratepayers, and especially the commenters' organization's 

members in northern Minnesota, will be paying for that hydropower through their rates. 

Commenters said therefore, Minnesota and its ratepayers should receive compliance credit for 

such expenditures.

Comment 194: MN - Carbon Emissions Leakage

Response 194: See section VIII.L. 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 the EPA's proposed Clean Power Plan does not address carbon emissions 

"leakage," and this is a crucial issue for Minnesota's manufacturers, economy and environment. 

Commenters said many commodities made in the U.S. are traded globally and if Minnesota 

manufacturers experience energy costs that our competitors in other states and countries do not, 

then Minnesota manufacturers likely sell less product and importers sell more. Commenters

stated using steel as an example, there are significantly more carbon emissions involved in 

shipping scrap from Minnesota across the ocean to Turkey or China, and then having that steel 

produced in those countries utilizing less costly but high carbon content electricity, and then the 

resulting emissions associated with the return shipping. Commenters said as proposed, the EPA's 

proposed Plan could dramatically increase costs of natural gas and electricity, while providing 

off-shore competition, and even competitors in other states, an advantage while at the same time 

creating carbon emissions leakage. Commenters stated the result for Minnesota would be 

emissions reductions that are insignificant when compared to the increases in emissions that 

would occur elsewhere in the U.S. and internationally.

Comment 195: MN - Minnesota would be forced to reduce carbon emissions by a higher 

percentage than other Midwestern states.
210

Response 195: See section I.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 stated forcing Minnesota to reduce its carbon emissions by 41% by 2030 is not fair. 

Commenters said other Midwestern states do not have to reduce by such a high percentage. 

Commenters stated Sherco has already been asked to research shutting down only 1 of the older 

generating stations to make the environmental emission reduction while keeping the other around 

for back-up or spare parts; reduced maintenance costs. Commenters said they are already putting 

together the action plans to make the catalytic reduction improvement on No.1& No. 2.

Comment 196: MN - A change would mean that Minnesota only needs to further reduce its 

emissions by 30% rather than the EPA-calculated 41%.

Response 196: For the EPA’s response to this comment, see the CO2 Emission Performance 

Rate and Goal Computation TSD for CPP Final Rule supporting the final CPP.

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

Commenters stated Minnesota has a strong RES that drives renewable energy development in 

Minnesota as well as in neighboring states to serve Minnesota's load. Commenters said the EPA 

used an in-state only renewable generation figure of 9,454 Gigawatt hours ("GWh") for 2012 to 

calculate the baseline emissions rate. Commenters stated the EPA has proposed that out-of-state 

renewable energy generation can be used for compliance purposes. Commenters stated if out-ofstate renewable generation contracted to serve Minnesota load is included in Minnesota's 

baseline emissions rate, Minnesota already has 12,100 GWh of renewable energy generation that 

would count for Clean Power Plan compliance. Commenters said this increase in renewable 

energy generation attributable to Minnesota reduces the gap between Minnesota's ultimate target 

and the status quo.

Commenters recalculated Minnesota's proximity to its goal using more current and accurate 

energy efficiency figures. Commenters said Minnesota tracks energy efficiency achievements 

through its Conservation Improvement Program ("CIP"). Commenters stated the sum of 

incremental savings from 2006 to 2012, assuming the same annual savings were achieved in 

2011 and 2012, is 4,902 GWh, which is a conservative figure. Commenters stated once this sum 

is discounted to account for the fact that only 83% of retail sales is served by in-state generation 

and multiplied by 1.0751 to account for losses between the meter and the generator, we reach a 

figure of 4,373 GWh of energy efficiency savings in Minnesota in 2012. 

Commenters stated if out-of-state renewable energy and Minnesota's CIP energy efficiency 

figures are included in Minnesota's 2012 baseline emission rate, the baseline emissions rates 

drops from 1,470 lbs/MWh to 1,243 lbs/MWh. Commenters said this change would mean that 

Minnesota only needs to further reduce its emissions by 30% rather than the EPA-calculated 

41% to comply with the 2030 Clean Power Plan target of 873 lbs/MWh.
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Comment 197: MN - Minnesota should not be penalized for our early action and for being a 

national leader in greenhouse gas reduction policy.

Response 197: See sections VI.D., VIII.B, and VIII.C. 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 it is imperative that Minnesota receive full credit for the costs of all early 

action in order for the Minnesota economy to remain competitive both nationally and 

internationally. Commenters said it is also imperative that the EPA considers the cost of any 

supplementary action when setting Minnesota's CPP targets. Commenters stated the Minnesota 

Next Generation Energy Act of 2007 ("NGEA") established a statewide renewable energy 

standard. Commenters said Minnesota's early action by adoption of legislation such as the 

NGEA led to significant repowering and emission reduction requirements which continue to 

successfully reduce statewide CO2 emissions. Commenters stated Minnesota regulators also 

require all utilities in the state to file an Integrated Resource Plan ("IRP") that includes 

consideration of CO2 environmental externalities. Commenters said all Minnesota filed IRPs 

must demonstrate that recently deployed and proposed environmental control retrofits deliver 

emission reductions that comply with recent environmental regulations addressing regional haze, 

fine particulates, ozone and mercury as well as including a range of CO2 emission costs. 

Commenters urged the EPA to consider that these early action and nation leading policy 

decisions have a true cost to current and future Minnesota ratepayers. Commenters said early 

renewable energy deployment actions, along with demand side management conservation and 

efficiency programs, should allow Minnesota to be rewarded and credited for existing programs. 

Commenters stated using the year 2005 as a baseline for the CPP assures Minnesota credit for 

their existing programs and avoids any punishment for the more recent Minnesota early action 

initiatives. Commenters said Minnesota's NGEA referenced 2005 as a baseline year for setting 

and tracking progress of the state's greenhouse gas emissions extending through 2030. 

Commenters stated the magnitude of CO2 emission reductions in the state from Minnesota's 

early action more than satisfies Minnesota's "fair share" contribution towards meeting overall 

United States climate policy objectives for improving the electric generating sectors emissions 

profile through 2030. 

Comment 198: MN - Retirements and Conversions of Coal-Fired EGUs.

Response 198: For the EPA’s response to this comment, see the CO2 Emission Performance 

Rate and Goal Computation TSD for CPP Final Rule supporting the final CPP.

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

Commenters stated the planned retirements of existing coal units in Minnesota will provide some 

additional emissions reductions. 
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Commenters stated the retirements will result in a net reduction in CO2 emissions. Commenters

said the exact level of avoided emissions will depend on how the coal units' generation is 

replaced in Minnesota's energy mix. Commenters stated in addition to retirements, two units 

(Laskin Energy Center Units 1 & 2) will be converted from coal to natural gas. Commenters said 

these units generated 191,860 and 174,506 MWh in 2012, respectively. Commenters stated using 

a conservative estimate that 25% of the CO2 emissions from these units slated for retirement or 

conversion could be avoided, Minnesota's estimated 2030 emissions rate drops even further - to 

916 lbs/MWh. Commenters said under this business-as-usual scenario, the Clean Power Plan 

would only drive a modest 5% additional reduction in emissions to meet the 2030 target. 

Commenters stated if 75% percent of the emissions from these units are avoided, Minnesota will 

surpass its Clean Power Plan target emissions rate in 2030 with no additional emissions 

reductions driven by the Clean Power Plan itself.

Commenters stated these scenarios demonstrate that despite what seems like an ambitious target 

for Minnesota, meeting this target can be achieved or nearly achieved under a business-as-usual 

plan. Commenters said Minnesota can continue to act as a leader in showing other states how to 

cost effectively achieve targets while simultaneously boosting the economy. Commenters stated 

these scenarios also demonstrate that the Clean Power Plan can go further in pushing states to 

make deeper emissions cuts necessary to combat climate change.

Comment 199: MN - Hydropower serving Minnesota retail customers

Response 199: 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 said another CPP issue the EPA must clarify is the future use of hydropower in the 

state's energy portfolio. Commenters said Minnesota will increase its reliance on carbon free 

hydropower in the foreseeable future and energy producers that utilize this resource should be 

given credit. Commenters stated the CO2 reductions from hydropower production benefit 

Minnesotans regardless of whether the generation is sourced from existing or new generation 

resources or whether these resources are located within Minnesota. Commenters asked that the 

EPA count all hydropower serving Minnesota retail customers towards state CPP compliance 

goals.

Comment 200: MS - Mississippi had 15th lowest carbon intensity rate, yet Mississippi's 

reduction goals are among the harshest

Response 200: See section I.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:
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Commenters stated that in 2012, Mississippi had the 15th lowest carbon intensity rate among the 

states, yet under the EPA's proposed Clean Power Plan, Mississippi's carbon intensity reduction 

goals are among the harshest, requiring a 62 percent reduction from the so-called 2005 baseline 

year.

Comment 201: MS - Goal is disproportionately low and would be devastating to Mississippi 

electric rates and hinder economic development.

Response 201: See section I.A. of the final rule preamble of the CPP for the EPA’s response to 

this comment. See section V of the preamble for how EPA revised its building block 

assumptions based on comments. Also see the Stranded Asset Analysis MEMO in the Docket.

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

Commenters argued the goal for MS is disproportionately low and would have a devastating 

impact on MS electric rates, hinder economic development in MS.

Commenters stated that the CO2 emission goals set for Mississippi by EPA are unreasonable, 

unachievable and unfair. Commenters added that the goals established for Mississippi are well 

below the proposed 111(b) NSPA of 1,100 lbs./net MWh for coal and 1,000 lbs./net MWh for 

gas. Commenters stated that Mississippi's goal is well below the national average of 991 lbs./net 

MWh. Commenters added that furthermore, the EPA's stated goal was a 30 percent national 

reduction of CO2 emissions below 2005 emission rates. Commenters stated that the final 

Mississippi goal of 692 lbs./net MWh represents a 64 percent reduction below the Mississippi 

2005 CO2 emission rate. Commenters concluded that this clearly shows a disproportionate 

requirement for Mississippi.

Commenters stated that the Mississippi Energy Institute (MEI) estimates that under the Proposed 

Rule, Mississippi electricity users would have to spend an additional dollar 14.2 billion for the 

State to be in compliance by 2030. Commenters stated that MEI estimates ninety-eight percent 

(98 percent) of that cost will go to build electric power generating facilities to meet the new 

generation mix goals, and most of that cost will be associated with meeting an aggressive 

renewable energy production target as our existing coal plants are prematurely retired. 

Commenters stated that MEI's 2030 Base Case, without the Proposed Rule, shows a generation 

mix of 63 percent natural gas, 20 percent coal, 15 percent nuclear and 2 percent wood, for a total 

capacity of 16,079 MW. Commenters stated that the generation mix in 2030 under the Proposed 

Rule would be 68 percent natural gas, 13 percent nuclear, 8 percent solar, 6 percent coal, 4 

percent wood and 3 percent wind for a total capacity of 18,127 MW. Commenters expounded 

that the additional 2,000 MW is necessary because of the installment of large amounts of 

intermittent renewables to meet the target set by the EPA in the Proposed Rule. Commenters

added that the MEI forecasts that 3,000 MW of solar and 800 MW of wind would also require 

about 69,000 acres of land. Commenters expounded that this cost does not include normal 

operational and maintenance cost through 2030, nor does it take into account the hundreds of 

millions of dollars of stranded cost as existing coal plants across Mississippi are prematurely 

retired. Commenters stated that for EPAM members, those coal plants continue to be financed 
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with loans from the Rural Utility Service. Commenters concluded that in short, the EPA 

Proposed Rule would have a devastating impact on Mississippi's electric rates and hinder 

economic development within the State.

Comment 202: MS - Devastating impact on the rural customer base by preventing the ability to 

provide reliable and affordable electricity

Response 202: See section I.A., V.A, V.C., V.D., V.E., and VII of the final rule preamble of the 

CPP and the CO2 Emission Performance Rate and Goal Computation TSD for CPP Final Rule 

supporting the final CPP for the EPA’s response to this comment.

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

Use of 2012 data. Commenters said there are numerous reasons for the disproportionate 

requirement for Mississippi including the many flaws associated with each of the building 

blocks. Commenters said in addition to the flaws associated with the building blocks, the EPA's 

use of 2012 generation and emission data for the calculation of the state's goal is unfair. 

Commenters stated the EPA picked a single year when the US experienced a record warm winter 

and the lowest natural gas prices in ten years, with natural gas generators displacing coal at 

record levels in many areas. Commenters said just 2 short years later, Federal Energy Regulatory 

Commission (FERC) in the Summer 2014 Energy Market and Reliability Assessment states, "In 

2012, natural gas was 57 cents cheaper than coal resulting in record natural gas fired generation. 

Higher natural gas prices this summer (2014) should make natural gas-fired generation less 

competitive with coal, with gas burn projected to be 2.5% lower than last summer and 17% 

below the summer of 2012." Commenters stated the EPA should base calculations from data 

collected in 2005 or at the very least take a multiyear approach.

Cannot achieve goal with existing resources. Commenters stated based on an evaluation of 

historical generation dispatch for an In-State Market and assuming plants slated for retirement in 

EPA's rule are in fact closed down or output is reduced, the Mississippi CO2 goals cannot be 

achieved with existing resources. Commenters said modeling of historic system dispatch for the 

years 2008 and 2012 shows that the best emission rate that could be achieved was 751 lbs/MWh 

for 2008 and 769 lbs/MWh for 2012, but only after additional costs of $106 Million and $42.8 

Million, respectively as economic dispatch was converted to low carbon dispatch. Commenters 

said EPA's 2020 MS goal of 732 lbs/MWh could not have been, and still cannot be, achieved.

Additional zero carbon sources needed to barely reach attain goal. Commenters stated in order to 

achieve the CO2 goal, installation of some form of zero carbon energy would be required. 

Commenters said if assumed that solar capacity could have been installed in the historical 

evaluation, as solar is the only possible renewable resource possible in Mississippi, 83.2 MW of 

solar capacity would have been required in 2008 and 158 MW in 2012. (Commenters stated this 

is based on an 18% capacity factor for solar which is typical for Mississippi.) Commenters said 

the capital cost associated with this capacity is $119 Million in 2008 and $225.7 Million in 2012 

and results in achieving a CO2 emission rate of 731.8 lbs/MWh in 2008 and 731.6 lbs/MWh in 

2012. Commenters stated these are barely below the 2020 CO2 goal for Mississippi and this is 
215

with the assumption that there are no unplanned or extended planned outages at the Grand Gulf 

Nuclear Station or one of the natural gas combined cycle facilities. Commenters said unlike other 

utilities in Mississippi, the owned generation and load served is located in the state and would all 

be subject to the inequitable goal the EPA established for Mississippi. Commenters said with 

load growth, there would be even more solar energy needed by 2020, with costs by then running 

into the hundreds of millions. 

Forced early retirement will cause stranded assets and job losses. Commenters stated a 

significant portion of generation and purchase power originates from coal-fired generation. 

Commenters said in recent times, a greater portion of Member System power needs has come 

from natural gas resources due to low natural gas prices. Commenters stated however, history 

has shown natural gas prices to be cyclical, thus maintaining fuel diversity is important to his 

organization in providing stability to the cost of energy for Members. Commenters said 

additionally, coal fired generation has been equipped with flue gas desulphurization (FGD) 

systems to control sulfur dioxide emissions; retrofitted with Selective Non-Catalytic Reduction 

(SNCR) systems to control nitrogen oxides (NOx); and is currently conducting testing on 

equipment and systems to meet the EPA's Mercury Air Toxic Standards (MATS). Commenters

said under this proposed rule, coal fired generation would be forced to shut down, resulting in 

significant stranded investment, much of which resulted from compliance with prior EPA rule 

making. Commenters stated this stranded investment will impose additional costs for members 

and significantly cripple the ability to stabilize the cost of energy for members going forward. 

Commenters said in addition to the issues surrounding the stranding of these investments, the 

EPA forced shut down of coal fired power plant will result in leaving 105 hard-working, skilled 

employees without jobs.

EE measures less efficient for residential consumers. Commenters stated the EPA's Proposed 

Rule requires electric consumers to implement additional energy efficiency (EE) measures thus 

placing an undue burden on consumers. Commenters said the rural members served by his 

organization are hit especially hard by these additional standards and costs. Commenters said in 

the Proposed Rule, the EPA fails to consider the characteristics of electric consumers served by 

rural electric cooperatives and instead makes broad EE assumptions across all states. 

Commenters stated this fails to account for the fact that EE measures are generally less effective 

for residential consumers as compared to industrial and commercial consumers.

RE target unreasonable. Commenters stated the EPA's proposal sets a target for Renewable 

Energy (RE) that is unreasonable and unsubstantiated for the State of Mississippi. Commenters

said the EPA presumption that renewable options can provide any appreciable amount of energy 

does not reflect the realities of state meteorology. Commenters stated Mississippi averages 52 

inches of rainfall annually and wind is intermittent during most of his organization's peak load 

season. Commenters said to build enough RE to reach the targets as proposed by the EPA, would 

require construction of inefficient RE generation thus again resulting in increased cost for 

Mississippians.

Lowest median household income, cannot afford rate increases. Commenters stated the EPA also 

does not take into consideration that Mississippi ranks dead last in median household income in 

the United States at $39,295, well below the US average of $51,058. Commenters said 
216

furthermore, the 2010 Hunger in America report showed that 47% of Mississippians reported 

having to choose between paying for food and paying for utilities. 

EPA overstepped authority, current goal is unachievable, effects will be devastating. 

Commenters stated the EPA has overstepped the bounds of its authority, the current goal for 

Mississippi is unachievable, and this rule, as proposed, will have devastating effects on 

members. Commenters said the EPA has no legal basis for issuing the Proposed Rule and it will 

not withstand judicial review. Commenters stated the Proposed Rule violates the Rural 

Electrification Act, the actions proposed are beyond EPA's authority, the Proposed Rule does not 

conform to CAA Section 111 and it will result in a regulatory taking for coal units. Commenters

stated the Proposed Rule's requirement that coal units retire early will have severe financial 

impacts on his organization and will strand assets in which significant investments were made. 

Commenters said these costs will drive up electricity rates which will devastate consumers. 

Commenters stated the coal unit retirements proposed in EPA's rule will leave his organization 

unable to provide reliable service to its members. Commenters said increased reliance on natural 

gas combined cycle and RE, as contemplated by the rule, is not sufficient to close the generation 

gap created by the retirements and makes the power grid less resilient in the face of abnormal 

conditions.

BB1 goal cannot be achieved. Commenters stated each Building Block that is part of the 

Proposed Rule is flawed and is based on unrealistic and inaccurate assumptions. Commenters

said the EPA's proposed six percent heat rate improvement across all coal units is not achievable 

and fails to recognize that most efficiency projects have already been undertaken. Commenters

stated there are no additional heat rate improvement projects that will realize this level of 

efficiency. Commenters said the Proposed Rule also does not include New Source Review 

exclusion for projects undertaken pursuant to Building Block 1.

BB2 70% CF not substantiated. Commenters stated the EPA's proposal in Building Block 2 that 

natural gas combined cycle operate at a 70% capacity factor is not substantiated by any existing 

operations. Commenters said more than a 32% capacity factor in combined cycle plants has 

never been achieved, and attaining a 70% capacity factor, if at all possible, would be 

uneconomical.

BB3 goals unrealistic. Commenters stated the EPA's RE goals in Building Block 3 are unrealistic 

because solar and wind energy have not been proven as viable in Mississippi and the goals do 

not account for biomass, the sole source of Mississippi's RE in 2012. Commenters stated the RE 

goals also penalize early action as $77.5 million has already been invested in the Grand Gulf 

Nuclear Station's Extended Power Uprate Project.

BB4 - don't get credit for early actions. Commenters stated the EE targets in Building Block 4 do 

not account for the investments already made. Commenters said successful EE programs are 

already in place. Commenters stated there should be credit for these programs, rather than be 

punished with the daunting task of pursuing additional EE projects and meeting aggressive 

guaranteed levels of EE.
217

Commenters stated the goals set forth in the Proposed Rule cannot be achieved. Commenters

said attempting to do so will have a devastating impact on rural customer base by preventing the

ability to provide reliable and affordable electricity.

Comment 203: MS - Goals are based on inaccurate data and flawed methods, and don't treat 

renewable potential and NGCC potential in comparable fashion

Response 203: See section V.D. of the final rule preamble of the CPP for the EPA’s response to 

this comment and more information about Building Block 2 and the CO2 Emission Performance 

Rate and Goal Computation TSD for CPP Final Rule supporting the final CPP.

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

Commenters stated proposed goals based on inaccurate data/flawed methodologies, and do not 

treat renewable potential and NGCC potential in a comparable fashion.

Commenters stated that the calculation of the proposed standards in the Entergy utility region is 

based on inaccurate data and/or flawed methodologies, which results in interim and final 

emission rate standards that are unrealistic and overly stringent. Commenters stated that the 

proposed standards also do not treat renewable potential and natural gas combined-cycle 

("NGCC") potential in comparable fashion. Commenters expounded that while renewable 

potential is assessed on a regional basis (although the regions used do not match power market 

boundaries), NGCC potential is assigned strictly on a situs basis, with disparate results for the 

Entergy region.

Comment 204: MS - Recommendations as a starting point for modifying the proposed rule with 

respect to Mississippi

Response 204: For the EPA’s response to this comment, see section V of the final preamble and

CO2 Emission Performance Rate and Goal Computation TSD for CPP Final Rule supporting the 

final CPP. EPA corrected its calculation of the Kemper facility generation and emissions.

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

Recalculate Mississippi goal. Commenters recommended that the Mississippi CO2 goal be 

recalculated based on the following:

1. Commenters said remove the 631,874 MWh from the denominator of the Mississippi 

CO2 goal calculation for "at risk" nuclear generation as there is no "at risk" nuclear 

generation in the state of Mississippi.

2. Commenters stated change the baseline for RE from 3% to 0%. Commenters said this 

would make the 2029 goal 7% rather than 10% and result in the denominator decreasing 
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from 5,458,430 MWh to 3,820,880 MWh. Commenters stated this difference in MWh 

should be replaced with coal generation.

3. Commenters stated remove EE from the goal calculation but allow achievements to count 

towards achievement of the goal. Commenters said this would remove 718,276 MWh 

from the denominator of the 2020 goal and 4,920,527 MWh from the denominator of the 

2029 goal as EE and be replaced with coal generation.

4. Commenters stated there are two suggestions for the handling of the Kemper IGCC 

facility:

a. Commenters said first, the EPA attributed 5,836,968 MWh to the Kemper IGCC 

facility. Commenters stated this is an apparent mistake as this would require the 

facility to have an annual capacity factor of 115%. Commenters stated this should 

be corrected.

b. Commenters stated second, the generation attributed to Kemper should be 

removed from the goal calculation and replaced with coal fired capacity.

5. Commenters stated replace generation shortfall in NGCC generation due to the difference 

in name plate capacity verses summer time capacity. Commenters said this creates a 

5,226,304 MWh generation shortfall for the year or 435,525 MWh per month. 

Commenters stated multiplying 435,525 MWh by the 5 summer months provides a 

shortfall of 2,177,625 MWh that should be replaced with coal generation.

Commenters stated the above changes resulted in revised CO2 goals for the State of Mississippi 

of 1,175 lbs/MWh in 2020 and 1,166lbs/MWh in 2029. Commenters said this request is 

reasonable as it raises the state goal slightly above that of the new source standard currently 

being considered. Commenters stated it makes absolutely no sense to have a standard for EGUs 

that is more stringent than that for new sources. Commenters stated this revised goal also puts 

Mississippi near the National Average Goal and is a 43% reduction from Mississippi's 2005 CO2 

emission rate well in excess of the desired 30% goal stated by the EPA.

Commenters stated Mississippi Power is currently building the nation's first integrated 

gasification combined cycle project with CCS in Kemper County, and rather than reward their 

research and development efforts, EPA's proposing a target more stringent than even this stateof-the-art technology could achieve.

Use actual lifetime average capacity for nuclear plants. Commenters recommended that the 

80.3% actual lifetime average for the nation's nuclear generating plants be considered rather than 

the 90% capacity factor used by the EPA when determining whether a state can meet CO2 goals 

established by the EPA. 

Eliminate interim targets and let states determine final compliance date. 

Commenters recommended that the EPA abandon the Proposed Rule's interim emission targets 

and that the states as part of their implementation plans be allowed to establish final compliance 

dates that are unit specific and based on the stated determined end of the useful life of a facility. 

Commenters stated this will lessen the economic impact of stranding an asset that has significant 
219

RUS debt and results in additional costs and difficulty in ability to finance other projects and 

infrastructure required to meet the EPA's proposed rule.

Comment 205: MS - The EPA's proposed final goal for Mississippi of 692 lbs CO2/MWh is 

overly aggressive and unachievable.

Response 205: For the EPA’s response to this comment, see the CO2 Emission Performance 

Rate and Goal Computation TSD for CPP Final Rule supporting the final CPP.

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

Commenters stated the EPA's proposed final goal for Mississippi of 692 lbs CO2/MWh is overly 

aggressive and unachievable. Commenters said the approach to use regional and national 

averages with regard to the building blocks, without following through with any sort of 

feasibility analysis at the state level, resulted in unrealistic goal projections for some states. 

Commenters stated for Mississippi, the goal path is riddled with unrealistic expectations. 

Commenters said the EPA continuously indicates that the goal path is not the only compliance 

path, and while that may be true, it is impossible to ignore the fact that the unrealistic goal path 

provided an unrealistic goal for Mississippi. Commenters stated before Mississippi can begin to 

move forward with the concept of developing a SIP under this proposal, the State must be 

allowed the opportunity to establish a realistic goal.

Comment 206: MS - The EPA formula hardwires in an assumed emissions rate for the Kemper 

IGCC plant that essentially treats it as a highly-efficient NGCC plant, which is inappropriate.

Response 206: For the EPA’s response to this comment, see the CO2 Emission Performance 

Rate and Goal Computation TSD for CPP Final Rule supporting the final CPP. EPA has adjusted 

its calculation for the Kemper facility per the comment.

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

Commenters stated the EPA formula hardwires in an assumed emissions rate for the Kemper 

IGCC plant that essentially treats it as a highly-efficient NGCC plant, which is inappropriate. 

Commenters said the EPA's assumed emission rate for Kemper is 806 lbs CO2/MWh, whereas 

the EPA's assumed average emission rate for Mississippi NGCC units is 848 lbs CO2/MWh. 

Commenters stated yet it is crucial to emphasize that performance of the technology at Kemper 

has categorically not been demonstrated. 

Comment 207: MS - The EPA's treatment of nuclear generation penalizes states with nuclear 

resources by including "at risk" nuclear in the denominator of the state goal
220

Response 207: 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 stated the proposed rule notes that existing and under-construction nuclear 

generation is CO2-free generation with relatively low variable operating costs. Commenters said 

the EPA proposes to include six percent of each state's historical nuclear capacity in the state's 

goal. 

Commenters stated concern that a recent uprate at Entergy's Grand Gulf Nuclear Station has 

resulted in an overly stringent calculation of Mississippi's goal and that states with existing 

nuclear that have invested in upgrades are being unnecessarily penalized. 

Commenters stated the EPA's treatment of nuclear generation penalizes states with nuclear 

resources by including "at risk" nuclear in the denominator of the state goal. Commenters said 

while they do not believe it is appropriate to penalize a state for having any zero-carbon emission 

nuclear capacity, the commenters asked that the EPA at least remove recent investment in 

nuclear generation, such as the Grand Gulf uprate, if nuclear generation remains in the 

denominator. Commenters stated Grand Gulf completed a power upgrade on June 16, 2012, 

increasing its production by over thirteen percent for a total output of 1,443 MW. Commenters

do not believe that including the full power output of Grand Gulf (following the uprate) in the 

calculation is appropriate. 

Comment 208: MS - The proposed rule does not provide flexibility to Mississippi.

Response 208: See section I.A. of the final rule preamble of the CPP and the CO2 Emission 

Performance Rate and Goal Computation TSD for CPP Final Rule supporting the final CPP for 

the EPA’s response to this comment.

EPA has regionalized building block two in the final CPP in a manner that it believes addresses 

the commenters concern regarding the state-focused impact of incremental NGCC at proposal.

See section VII of the preamble for the state goals in this final CPP Rule.

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

BB2 would effectively eliminate coal-fired generation. Commenters stated based on the data the 

EPA used in calculating the emissions rate goals for Mississippi, 7500 GWh of electricity were 

generated in the state from coal-fired resources in 2012. Commenters said the re-dispatch 

building block zeroes out that low-cost source of electricity, by assuming that output from 

NGCC plants is increased to more than 63 percent of maximum annual generation (i.e., full 

capacity output every hour of the year). Commenters stated this increase, from a 2012 level 

corresponding to 46 percent of theoretical maximum output, fully displaces all coal generation in 

Mississippi. Commenters stated while the EPA asserts that this is not a requirement of the plan, 

but rather just one of the building blocks that can be considered in developing a compliance plan, 
221

along with the renewable energy and energy efficiency components, the commenters do not 

agree with the EPA that the projected levels of these other building blocks will be achievable for 

Mississippi. Commenters stated the result is that Building Block 2 would effectively eliminate 

coal from Mississippi's resource mix. Commenters said according to the EPA's goal computation 

data, Mississippi would be one of only five states that had in excess of 15 percent coal generation 

in 2012, but would have coal zeroed out as a result of redispatch under Building Block 2.

Illustration of lack of flexibility. Commenters stated to illustrate the lack of flexibility afforded to 

Mississippi under the Clean Power Plan as proposed, consider the impact if Mississippi 

attempted to fashion a compliance plan targeting NGCC operation at 60 percent of potential 

maximum annual output instead of the 63 percent assumed by the EPA. Commenters said under 

the Clean Power Plan methodology, that would "allow" retention of 1700 GWh of coal 

generation (with the assumed 6 percent heat rate improvement) - less than one sixth of the 2012 

generation level - but would require offsetting increases in other building blocks. Commenters

stated implementation of the other building blocks to achieve the 2029 target emission rate of 

692 lbs/MWh of CO2 would be extremely difficult, and certainly not adequately demonstrated. 

Commenters said applying the renewable energy building block, Mississippi would have to more 

than double the quantity of renewable generation relative to the EPA-derived target to an 

equivalent of more than 3800 MW of wind capacity by 2029. Commenters stated only Texas, 

Iowa, and California currently have this much wind generation capacity. Commenters said 

relying on increased energy efficiency under Building Block 4 would also require doubling the 

already difficult EPA-derived target to accommodate retention of the same small portion of coal 

generation. 

Commenters stated even the practically infeasible scenarios described above would not represent 

useful flexibility, however, because the small amount of accommodated coal generation would 

likely not allow the continued operation of even one coal-fired power plant under expected 

operational constraints. Commenters said there are currently four coal-fired generating facilities 

in Mississippi. 

Commenters stated the Watson units are currently expected to be converted to burn natural gas, 

and thus are not candidates for retention as coal-fired resources going forward. Commenters said 

of the remaining plants, only Morrow operated at a level in 2012 that would be accommodated 

under the flexibility scenarios under which 1700 GWh of retained coal generation could be 

"purchased" at the expense of substantial increases in targets under Building Blocks 3 and 4. 

Commenters stated Plant Daniel would also be a candidate for retention, since it is nearing 

completion of a $660 million environmental retrofit to install flue gas desulfurization for control 

of sulfur dioxide emissions. Commenters stated however, the efficient operating point for the 

retrofitted units would be much higher than could be accommodated under any feasible 

flexibility scenario. Commenters said moreover, a further planned retrofit to install selective 

catalytic reduction ("SCR") to control for nitrous oxide emissions, would result in operating 

restrictions that would require operation above 90 percent of capacity, likely in excess of 8000 

GWh annually. Commenters stated the nature of efficient and effective operation with SCR is 

that a plant must be either fully on or off, and cannot be operated at low load or cycled to provide 

load-following service. Commenters said these operating realities also mean that Mississippi 

would not easily be able to attain its fuel diversity objectives through regional coordination. 

Commenters stated marginal exchanges with other states via joint plans or regional trading 
222

would be insufficient to accommodate efficient operation of even a single coal-fired plant in 

Mississippi.

Commenters stated the lack of real flexibility is not only a question of the infeasibility of 

retaining any coal generation, but is also an issue with respect to gas-fired generation. 

Commenters said because the Mississippi emissions rate goals throughout the 2020-30 

compliance period are all substantially below the already low rate the EPA has assumed for 

existing combined cycle facilities, it is not possible for Mississippi to rely on gas-fired 

generation to manage the challenges of increasing the levels of renewable generation and energy 

efficiency. Commenters stated that is, because the emissions rate for existing NGCC units is well 

above the target rates for the state, increasing NGCC generation only increases the amount of 

renewable energy and energy efficiency needed to meet the goals. Commenters said thus, even 

though application of Building Block 2 results in an assumed capacity factor of 63 percent for 

existing NGCCs in Mississippi, rather than the maximum redispatch assumption of 70 percent, 

this does not imply that Mississippi has any more flexibility via extra "headroom" in gas 

generation. Commenters stated since coal generation is effectively prohibited under the plan, 

there is no opportunity to run the gas-fired plants more to allow flexibility in achieving the other 

building blocks. 

Commenters said as proposed, the Clean Power Plan offers Mississippi no practical degree of 

flexibility. Commenters stated rather, each building block would impose a significant and costly 

burden on Mississippi electricity consumers. 

Comment 209: MO - Rate Impacts Arising From the EPA's Proposed CPP

Response 209: For the EPA’s response to this comment, see the CO2 Emission Performance 

Rate and Goal Computation TSD for CPP Final Rule supporting the final CPP.

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

Commenters stated meeting the EPA's unrealistic interim targets would require the installation of 

1,200 MW of NGCC capacity. Commenters stated in addition, this capacity would need to be 

forced to run at capacity factors substantially in excess of what is dictated by conventional 

security-constrained least cost economic dispatch protocols.

Commenters stated compliance with the EPA's proposal would impose an additional $4 billion of 

cost on its Missouri residential, commercial and industrial customers. Commenters said further 

examination of that analysis shows that between $1 billion and $2 billion of that additional cost 

would be incurred in the period 2019 through 2023, with electric rates being increased by 10%-

15%, and perhaps more, depending upon the price of natural gas. Commenters stated these are 

increases that customers can ill-afford to pay, especially when the same emission reductions can 

be achieved by 2034 without incurring these excess costs. 
223

Comment 210: MO - Proposed rules do not provide an opportunity for a state to receive credit 

for pre-2012 renewable energy projects

Response 210: See sections VI.D., VIII.B., and VIII.C. 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 many of Missouri's existing renewable projects were developed in response 

to the MoRES; yet the proposed rules do not provide an opportunity for a state to receive credit 

for pre-2012 renewable energy projects. 

Comment 211: MO - Reliance on re-dispatch makes it impossible to achieve the reductions 

mandated in the state goals

Response 211: See section V.D. of the final rule preamble of the CPP for the EPA’s response to 

this comment and more information about Building Block 2 and the CO2 Emission Performance 

Rate and Goal Computation TSD for CPP Final Rule supporting the final CPP.

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

Commenters stated building block 2 is simply not attainable at all because MRES does not have 

any existing NGCC plants to which it could re-dispatch its coal generation. Commenters said 

this is a significant concern because the Clean Power Plan relies heavily on building block 2 to 

attain almost one-third of the reductions that are used to set state goals. Commenters stated this 

reliance on redispatch makes it impossible to achieve the reductions mandated in the state goals.

Comment 212: MO - Missouri Can Cut Greenhouse Gas Emissions from Power Generation by 

30 Percent & Criteria and Hazardous Air Pollution by 60 to 70 Percent; planned coal-fired EGU 

retirements will achieve most of reductions required

Response 212: For the EPA’s response to this comment, see the CO2 Emission Performance 

Rate and Goal Computation TSD for CPP Final Rule supporting the final CPP.

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

Emission reductions expected. Commenters stated more efficient use of existing infrastructure 

CO2 emissions in 2005 from coal, natural gas, and oil-fired electrical power generation in 

Missouri were 83.4 million tons. Commenters said 81.7 million tons of this came from the 

burning of 45.8 million tons of coal. Commenters stated if the existing natural gas (NG) 

generating capacity was fully utilized, displacing a portion of the coal in supplying this same 

energy, 16.7 million tons less of CO2, 66.8 million tons of CO2 would be emitted, a 20 percent 

reduction in Missouri's overall GHG emissions from power plants. Commenters stated NOx 

emissions would be reduced by nearly 45 percent. SO2, mercury, and a long list of additional 
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HAP emission reductions of 50 percent could be achieved, utilizing existing infrastructure. 

Commenters said additional CO2 reductions of up to 13.9 percent could be achieved by more 

fully utilizing nuclear and hydroelectric generating capacities.

Commenters stated recognition of the potential of this approach has been growing as states and 

nations explore readily deployable options for reducing GHG emissions. Commenters said the 

chairman of the Federal Energy Regulatory Commission, Jon Wellinghoff, recently testified at a 

Senate hearing that natural gas, in combination with renewable resources and energy efficiency, 

could be a near-term bridge until zero-carbon technology is widely accessible.

Already announced plant retirements. Commenters stated in addition to the reductions Missouri 

can achieve through compliance with existing renewable and efficiency policy, Missouri will 

achieve over half its needed reductions simply by following through with the plant retirements 

already announced for the near future.

Commenters said Missouri's mass-based reduction target is approximately 15.13 million MT by 

2030. Commenters stated under this mass-based analysis, more than half of that required 

reduction (57%) will be made up by plant retirements. Commenters said Ameren Missouri plans 

to retire its Meramec plant by 2022, making up 28% of Missouri's total needed reduction and 

67% of its own needed reduction.

Commenters performed an analysis of the mass-based reductions required by each electrical 

generating unit (EGU) in Missouri, as compared to the reductions that will be achieved by plant 

retirements already announced for the near future. Commenters said both of these analyses 

demonstrate that Missouri's required reductions target is easily achievable with few additional 

commitments from Missouri EGUs.

Comment 213: MO - Affected Units

Response 213: The EPA believes all coal steam EGUs greater than 25 MW are likely affected 

units under the final CPP applicability criteria. Units GT1, ST1, and 2 are excluded because they 

have a nameplate capacity of 25 MW. This inventory of likely affected units does not constitute 

an applicability determination. See section VII.E of the preamble for further discussion of how 

future applicability status changes interact with state goals.

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

Commenters stated EPA defines an affected electric generating unit (EGU) "as any boiler, 

integrated gasification combined cycle or combustion turbine that (1) is capable of combusting at 

least 250 Million Btu per hour; (2) com busts fossil fuel for more than 10 percent of its total 

annual heat input; (3) sells greater than 219,000 MWh per year to a utility distribution system; 

and (4) was not in operation or under construction as of January 8, 2014 (emphasis added)" 

(Page 34854, Section V (C) ). The commenters stated according to this definition, the EPA has 

erroneously included Blue Valley (BV) Units 1 and 2 in Independence, Missouri as regulated 

units in its October 2014 NODA Data Files: 2010 and 2011 Unit Level Data Using eGRID 

Methodology (xls). The commenters said BV Units 1 and 2 have identical generators rated at 
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29,411 KVA (= 24.999 MW or KVA x 0.85 power factor) and turbines rated at 22 MW. The 

commenters said the turbines restrict the net available energy sold to utility distribution system to 

a theoretical maximum of 192,720 MWh (22 MW x 8,760 hr); and, therefore BV units 1 and 2 

must be excluded as affected units. The commenters added the maximum net energy sales for 

these units in the last 20 years was 117,637 MWh, well short of the theoretical maximum MWh. 

Commenters stated although BV Unit 3 has a generator rating of 65 MW, a turbine rating of 58 

MW, and a theoretical annual maximum energy production of 508,080 MWh, it does not operate 

as a base load unit having an average capacity factor of only 18% over the last 20 years. The 

commenters said it is apparent from the annual net energy sales for Blue Valley Unit 3 from 

1994 to the present that the maximum net sales for BV3 was 195,188 MWh with an average of 

92,309 MWh over the last 20 years. The commenters stated that Blue Valley Unit 3 should also 

be excluded as an affected unit. 

Commenters stated EPA defines an affected EGU as a "steam generating unit that has a base 

load rating greater than 73 MW (250 MMBtu/h) heat input of fossil fuel (either alone or in 

combination with any other fuel) and was constructed for the purpose of supplying more than 

219,000 MWh net electric output to a utility distribution system on an annual basis" (Page 

34954, Section XII, section 60.5795 (b) (1)). The commenters said although this definition of an 

affected EGU is inconsistent with that presented in Section V of the proposed rule, BV 1 and 2

must still be excluded because they also do not meet either of these conditions. The commenters

said according to this section's definition, BV 3 must also be excluded as an affected EGU since 

its rating is less than 73 MW; BV 3 net sales have not exceeded 219,000 MWh for the last 20 

years. 

Commenters, state air quality permitting authorities, requested that the EPA work with the State 

of Missouri after the section 111(d) applicability criteria are more clearly defined so that 

calculation of the goal for the State of Missouri will reflect use of an accurate list of affected 

sources in the final rule.

Comment 214: MT - Revisions

Response 214: For the EPA’s response to this comment, see Chapter 4 of the GHG Mitigation 

Measures TSD for CPP Final Rule and the CO2 Emission Performance Rate and Goal 

Computation TSD for CPP Final Rule supporting the final CPP. See section V.A. of the final 

rule preamble of the CPP for more information about Building Block 4. See sections VI.D., 

VIII.B., and VIII.C. of the final rule preamble of the CPP for more information about early 

action credit.

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

Commenters stated on page 4-22 of the GHG Abatement Measures TSD, the renewable 

electricity numbers shown in Table 4.6 for Montana are incorrect for all years and do not match 

the numbers used elsewhere by the EPA. Commenters said for instance, in 2030, Montana's 

renewable electricity target should be 2,723 GWh rather than the 2,848 GWh shown in the table. 
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Commenters stated the renewable energy percentage numbers for Montana in Table 4.7 on page 

4-24 are also incorrect (most likely because they are using the MWh numbers from Table 4.6).

Commenters stated Montana has adopted the 2009 IECC not the 2006 as the text using EPA's 

state map indicates. See: http://bsd.dli.mt.gov/bc/current_codes.asp. 

http://www.energycodes.gov/adoption/states/montana.

Commenters stated the EPA improperly assumes that Montana can implement additional 

demand-side EE, such that consumers reduce energy use by as much as 12% by 2030 to offset 

coal-fueled EGU generation. Commenters said as with the EPA's renewable energy, the EPA 

presumes to dictate "best practices" to states for energy conservation programs provisions. 

Commenters stated but, as with renewable energy, the EPA neither has the expertise nor the 

authority to dictate to Montana what "best practices" are for adopting programs that conserve 

energy. Commenters asserted this overall method has resulted in a goal which is far too 

ambitious for Montana.

Commenters stated the Proposed Rule does not meet the statutory standard of showing that its 

EE projections have been "adequately demonstrated." Commenters said indeed, the sheer 

magnitude of the EPA's EE goal is staggering. Commenters said the EPA projects that in 2030, 

electricity usage will be 10% below the business-as- usual case. Commenters stated according to 

the EPA, electric consumption in 2030 will be little more than it is today and will actually 

decline between 2020 and 2030. Commenters stated according to the U.S. Census, population is 

expected to rise to 358,471,000 people by 2030, an increase of 37,108,000 from the projected 

2015 level of 321,363,000, or an average of more than 2 million people per year. Commenters

stated further, the EPA has not evaluated this issue relative to Montana. Commenters said the 

EPA's proposal thus arbitrarily assumes that Montana's population and economy can grow, much 

less thrive, without electricity growth. Commenters said the EPA's conclusion is unsubstantiated.

Commenters stated using the EPA's cost assumptions, commenters project additional energy 

efficiency costs to be $0.6 billion on a 2013 net present value (NPV) basis. Commenters said 

however, since the EPA makes the assumption that no reduction in Montana's coal-fired 

generation would occur, the additional EE is assumed to result in Montana exporting additional 

energy out of state, which would lead to additional revenues that would offset some of the added 

EE costs. Commenters stated using a projected price for these exports at the EPA's wholesale 

energy prices, a $0.32 billion shortfall exists that would have to be made up, presumably through 

additional charges to retail customers. Commenters said the higher costs to the utilities, coupled 

with a lower sales base over which fixed costs are recovered, are projected, in turn, to result in 

higher prices for consumers.

Commenters stated further, Montana ratepayers have already invested in EE programs and 

renewable energy. Commenters said but under the Proposed Rule, these ratepayers would receive 

little credit for the beneficial impact that these investments may have. Commenters stated 

instead, allowing Montana to count pre-2020 emission reductions would recognize the benefit of 

these contributions and would avoid sending a distorted price signal to states to wait until 2020 

to implement emission reductions. Commenters said the most reasonable approach to providing 

early action credit would be to allow any emission-reducing actions that take place after the 

baseline year to count toward compliance with state goals. Commenters said such emission 
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reductions would not already be included in state goal calculations, so there would be no risk of 

double-counting. Commenters stated accordingly, Commenters urged the EPA to provide early 

action credit for at least those pre-2020 actions that states can demonstrate took place any time 

after the date of the Proposed Rule.

Comment 215: MT - Montana's Target Should Be Increased

Response 215: For the EPA’s response to this comment, see the CO2 Emission Performance 

Rate and Goal Computation TSD for CPP Final Rule supporting the final CPP. At proposal, 

EPA relied on a within state application of the building blocks which limited the potential of 

BB2 to have an impact in Montana as the state had not existing NGCC units. In this final rule, 

EPA has modified its approach to a regional assessment of the building blocks. As a 

consequence, Montana’s state goal has been adjusted from the proposed level.

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

Commenters opposed the proposed carbon reduction target for Montana. Commenters said 

Montana received the second weakest carbon reduction goal in the nation. Commenters stated 

the 21% rate reduction goal by 2030 is based on calculations that underestimated Montana's 

clean energy potential. Commenters said Montana could easily meet a 21% rate reduction goal 

without doing much beyond business as usual. Commenters stated Montana can cost-effectively 

replace coal with renewable energy and energy efficiency while saving consumers money, 

benefitting the economy, and creating sustainable jobs. Commenters said given the urgency of 

addressing climate change, the EPA should set a more reasonable goal for Montana of 30% 

reduction by 2030.

Comment 216: MT - Tapping into our abundant renewable energy and energy efficiency 

resources could transform Montana's electricity mix and make power more affordable for 

Montanans.

Response 216: For the EPA’s response to this comment, see the CO2 Emission Performance 

Rate and Goal Computation TSD for CPP Final Rule supporting the final CPP.

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

Montana's Current Electricity Mix. Commenters stated Montana’s current electricity mix 

exports most of the electricity generated in state. Commenters said in fact, only half of the 

electricity generated in Montana is consumed in state. Commenters stated this is due to the

relatively small population size compared with large, centralized electricity generation facilities -

primarily the Colstrip Generating Station in Colstrip, Montana. Commenters said the Colstrip 

plant is one of the highest greenhouse gas polluters in the nation, pumping an average of 15 

million tons of carbon dioxide into the atmosphere each year. Commenters said the Colstrip 

Generating Station is a four unit, 2,094 megawatt facility in southeastern Montana. Commenters

stated Colstrip is the second largest coal plant west of the Mississippi River and is owned by a 
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combination of regulated utilities and unregulated electricity suppliers. Commenters said Puget 

Sound Energy based in Washington State owns the largest share of Colstrip and PPL, based in 

Allentown, Pennsylvania, has the second largest ownership share. Commenters stated most of 

the owners reside in the Pacific Northwest. Commenters said only NorthWestern Energy (NWE), 

which owns 222 megawatts of Colstrip Unit 4, provides regulated electricity service to Montana.

Commenters stated at present, electricity generated in Montana comes from two primary sources: 

coal and hydropower. Commenters said about 50% of Montana's electricity generation comes 

from coal. Commenters stated hydropower makes up about 40% of the electricity generation mix 

while wind comprises about 5.0% of electricity generated in Montana. Commenters said the 

remaining fraction of electricity generation comes from natural gas and petroleum. 

Commenters stated Montana's currently coal-dominated electricity mix is unsustainable and 

outdated and does not represent the vast clean energy potential. Commenters said tapping in to 

the abundant renewable energy and energy efficiency resources could transform Montana's 

electricity mix away and make power more affordable for Montanans.

Comment 217: MT - RE

Response 217: The EPA has revised its block three quantification based on comments and our 

further consideration. See Section V.A. and V.E of the final rule preamble of the CPP for more 

information about building block three.

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

Commenters stated a recent National Academy of Sciences study ranked Montana's wind energy 

potential as tied with Kansas for second best wind potential in the United States. Commenters

said the study estimated that Montana's abundant and high quality wind resource could meet in--

state energy needs 370 times over. 

Commenters stated although Montana ranks second in wind energy potential, it only ranks 23rd 

in the amount of installed wind energy capacity. Commenters said wind makes up over 90 

percent of the eligible renewable energy projects developed to meet Montana's Renewable 

Energy Standard (RES). Commenters said the state RES requires regulated utilities to meet 15 

percent of their electricity demand with renewable resources by 2015. Commenters stated 

Montana's high quality wind resource enabled utilities to meet the 15 percent standard in 2012 -

three years earlier than legally required. Commenters said Montana has developed over 600 

megawatts of wind energy in less than ten years. 

Commenters stated Montana could develop over 5,000 megawatts of wind energy by 2030. 

Commenters said that is enough wind energy to power nearly 5 million homes. Commenters

stated the EPA should base its renewable energy building block on this type of wind potential, 

not outdated state policies like the RES.

Commenters stated that, the states should adopt a renewable portfolio standard or adopt a more 

aggressive standard if they already have one in place. Commenters said that the amount of 
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renewable power EPA is planning to bring online in the compliance timeframe of the rule is not 

based on accurate assumptions and is not reasonable or feasible.

Commenters stated that, EPA started with the wrong numbers and applied an unrealistic growth 

factor which resulted in the wrong conclusion. Commenters said that EPA used all the wind 

power generated in Montana in their calculation including the wind power exported to other 

states. Commenters said renewable energy exported out of Montana should not be required when 

setting the state's goals. Commenters said that the effect of the error will improperly increase the 

stringency of Montana's goal.

Commenters stated that, by 2030 Montana would have to add between 2.7 and 4.4 million MWh 

per year of new renewable energy resources to comply with the Proposed Rule. Commenters 

said, the generation resources would range from initial investment from $0.56 billion to $3.25 

billion (2013 NPV). Commenters said that, an additional cost of between $0.06 and $0.14 billion 

(2013 NPV) is needed to improve the transition infrastructure. Commenters said that the increase 

in transition cost were not included in the EPA estimated impact cost. Commenters said that 

including the generation and transmission cost will be range of $0.62 and $3.38 billion (2013 

NPV) to comply with the Proposed Rule. Commenters said that pricing these exports at EPA's 

projected wholesale energy prices results in a projected $775.6 million shortfall.

Comment 218: NE - general goals

Response 218: For the EPA’s response to this comment, see the CO2 Emission Performance 

Rate and Goal Computation TSD for CPP Final Rule supporting the final CPP.

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

Commenters stated if the CPP rule as proposed is to maintain flexibility and adherence to the 

intent of the CAA, [then] the commenters requested EPA re-evaluate its assumptions in setting 

the emission standards for NE and surrounding states, and to consider the limitation of resources 

that individual facilities will need to address, including: reliability of wind energy relative to 

reliability and affordability; multistate service region and allocation of emissions reductions 

requirements.

Comment 219: NE - incorrect data for NE NGCC plants used by the EPA in calculation of NE 

goal

Response 219: For the EPA’s response to this comment, see the CO2 Emission Performance 

Rate and Goal Computation TSD for CPP Final Rule supporting the final CPP. In regards to 

Beatrice Power Station, the EPA relies on summertime capacity reported in this final rule. This 

appears to address the concern raised by commenters as the summertime capacity is significantly 

lower than nameplate. Regarding the Terry Bundy Generating Station, the prime mover type of 
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unit 4 was changed to GT and the unit was consequently excluded from the baseline inventory of 

likely affected units.

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

Commenters stated data used by EPA in the calculation of the CO2 emissions goal relating to 

existing NGCC capacity located in Nebraska is incorrect. The commenters said the incorrect data 

used resulted in an over calculation of existing NGCC capacity located in Nebraska and has 

caused an error in the calculation of the CO2 emissions goal relating to existing NGCC capacity 

located in Nebraska. The commenters did not believe that these inaccuracies substantially impact 

the Nebraska target, but nonetheless the corrections should be addressed. 

Commenters said there are two combined cycle facilities located in Nebraska; they are the 

Beatrice Power Station, ORIS Code 8000, operated by the Nebraska Public Power District, and 

the Terry Bundy Generating Station, ORIS code 7887, operated by the Lincoln Electric System. 

Commenters said the nameplate capacity (MW) data used by EPA for the Beatrice Power Station 

is incorrect; the combined cycle system at the Station consists of two CTs and one Steam 

Turbine. Commenters said the data used by EPA listed each CT at 104.7 MW and the Steam 

Turbine at 93.9 MW; each CT is actually rated at 76.6 MW; the Steam Turbine is rated at 93.9 

MW. 

Commenters said the data used by EPA for the Terry Bundy Generating Station is also incorrect; 

the combined cycle system at the Station consists of two CTs and one Steam Turbine; the Station 

also has one simple cycle CT. Commenters said the data used by EPA listed all three of the CTs 

at the Station as combined cycle units; only two of the CTs are combined cycle; the nameplate 

capacities listed for all the units were correct. 

Comment 220: NV - goals

Response 220: For the EPA’s response to this comment, see the CO2 Emission Performance 

Rate and Goal Computation TSD for CPP Final Rule supporting the final CPP.

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

Commenters asserted that available credible evidence requires that the numeric values in each 

block used to calculate the final goal must be re-evaluated and a new goal recalculated. 

Commenters said the following Scenarios were evaluated by the Nevada Agencies that reflect 

more feasible goals: 

• Scenario 1 contemplates the retirement of Valmy in 2025 pursuant to the current 

PUCN schedule; the continued operation of TSPP through 2030; a 1.5% heat rate 

efficiency improvement at TSPP; the use of USEPA's alternate RE; and USEPA's 

proposed EE values. 
231

• Scenario 2 contemplates Valmy's retirement in 2025; TSPP's continued operation 

through 2030; a 1.5% heat rate efficiency improvement at TSPP; the total Nevada 

RE generation minus exported RE; and USEPA's proposed EE values. 

Commenters said the above two calculations respect the remaining useful lives of Valmy and 

TSPP, as required by the plain language of Section 111(d) of the Clean Air Act; the first uses the 

alternative RE approach, whereas the second calculation removes the exported RE from the goal 

computation. The commenters said the Nevada Agencies believe that both goal computations 

reflect more feasible goals that consider the remaining useful lives of the affected sources. The 

commenters added the Nevada Agencies seek a firm commitment from the USEPA that it will 

work with the Nevada Agencies on the goal calculation before the final rule is issued. 

Interim

Commenters stated despite EPA's statements that that the Proposed Rule is not intended to force 

a state to shutdown coal plants, the 2020 interim emission limit of 697 lb/MWh proposed by 

EPA would require Nevada to shutter the State's coal-fired fleet, including the TS Power Plant. 

The commenters said the closure of a facility under Section 111(d) is per se unreasonable; 

moreover, an EPA action that results in the forced closure of a facility with more than 30 years 

of useful life remaining, at stranded costs estimated at $450 million, would constitute a 

regulatory taking. The commenters said EPA has neither the constitutional nor the statutory 

authority to finalize the Nevada emission limit in light of these realities.

Commenters stated EPA claims that the 10-year phase-in period is intended to mitigate the 

stringency of the standard; in the case of Nevada, however, the 2020 limit would require the 

State to shutter its coal-fired fleet of EGUs. The commenters said specifically, 2020 is the 

mandated date by which states must achieve the reductions set forth in Building Blocks 1 and 2; 

by 2020, the EPA-mandated CO2 emission rate for Nevada would drop from the baseline level 

of 1,091 lb/MWh to 697 lbs/MWh (a 37% decrease). The commenters said at this emission rate 

level, there is no allowance for coal-fired generation after 2020; the increment between the 2020 

and the final 2030 goals simply reflects the year-to-year impacts of Building Blocks 3 and 4 for 

the period of 2020-2030, which do not substantially reduce the emission rate from 2020 levels. 

The commenters said the impossibility of meeting this target reflects the unrealistic increase in 

NGCC utilization by 2020, and EPA's failure to properly account for Nevada's substantial 

investment in renewables prior to the 2012 baseline year.

Commenters stated in calculating the interim performance goals, EPA assumes that all of 

Nevada's NGCC units would increase utilization to approximately 50% by 2020; as an initial 

matter, a substantial shift to NGCC generation over a six-year period is practicably unworkable 

and fails to account for substantially higher natural gas utilization in the summer months, when 

excess capacity is simply not available. The commenters said Nevada does have over 5 GW of 

NGCC generating capacity, which is located in southern Nevada; this generating capacity was 

constructed largely to accommodate summer electrical loads in the Las Vegas area and in 

southern California. The commenters said in the summer months, load demands in these areas 

can be double of the winter months. The commenters said although there may appear to be 

excess NGCC on an annual basis, that generation is not likely to be available during the summer 

months to make up for the lost coal generation. The commenters said by averaging the excess 
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NGCC capacity over a year, EPA comes up with an unreasonable requirement for increasing 

NGCC utilization in Building Block 2, which in turn results in an unreasonable 2020 interim 

emission limit.

Comment 221: NV - affected sources

Response 221: The EPA considers all coal steam units with a nameplate capacity above 25 MW 

to be likely affected units. This does not constitute an applicability determination, but EPA has 

left TS Power Plant in its inventory of likely affected EGUs. See section VII.E of the preamble 

regarding future changes in applicability status.

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

Commenters stated the Proposed Rule improperly designates the TS Power Plant as an "affected 

steam generating EGU" for purposes of calculating the baseline and the state emission "goals" 

for Nevada; as a result, the TS Power Plant must be included in the Nevada plan implementing 

EPA's performance standards. The commenters said the TS Power Plant, however, is unique 

among the facilities that EPA asserts are regulated under the Proposed Rule; specifically, 

Newmont constructed the TS Power Plant for the purpose of supplying more than 85% of its 

potential electric output to Newmont's mines; therefore, the TS Power Plant is not an "affected" 

EGU and should be excluded from the final rule and from development of the Nevada plan 

implementing the final standards.

Commenters stated consistent with its stated purpose, NNEI sells a limited amount of the 

electricity generated at the TS Power Plant to NV Energy for distribution to the grid. 

Commenters stated the excess power that is not destined for Newmont's mine sites is sold to NV 

Energy; this sliver of the TS Power Plant's total generation is the only electricity that is sold to a 

utility distribution system; to facilitate the delivery of power from the TS Power Plant to the 

various mine sites, NNEI entered into two agreements with NV Energy: 

• Confirmation Agreement (August 22, 2007): This agreement between NNEI and 

NV Energy provides for the sale of power from the TS Power Plant to NV 

Energy; specifically, the agreement partitions the power generated at the TS 

Power Plant into three blocks, designated Blocks 1,2 and 3 and specifies the 

contract power purchase price for each block; Block 1 is power sold to NV 

Energy and is, in effect, payment to NV Energy for ancillary services and to 

guarantee service to Newmont mine sites; Block 2 power is power sold to NV 

Energy and destined for re-purchase by Newmont at the individual mine 

sites; Block 3 power is excess power available for sale by NNEI to NV Energy or 

other third parties. 

• GS-4-NG Electric Service Agreement between NV Energy and Newmont U.S.A. 

Ltd. dba Newmont Mining Corporation (August 22, 2007): This agreement 

specifies the energy rates and conditions for the purchase of TS Power Plantgenerated power from NV Energy at the Newmont mine sites; the rate schedule 
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includes Newmont's cost of production plus transmission and distribution costs 

established by NV Energy. 

Commenters said the Block 1 power is payment for the use of NV Energy's transmission system 

and therefore is not intended for sale to a "utility distribution system." Commenters said the 

Block 2 power is generated for transmission to Newmont's mines, and does not enter a "utility 

distribution system." Commenters said the Block 3 power which is the excess power sold to NV 

Energy for distribution to the grid. Commenters said consistent with the stated purpose for 

construction of the TS Power Plant, over the eight years that the plant has been operational 

(including a partial year during plant commissioning), an average of 73% of the electricity 

generated by the TS Power Plant was sent to Newmont's mines, TS Power Plant continues to 

operate in support of its narrow purpose: to provide reliable electricity to Newmont's mining 

operations. 

Commenters stated the TS Power Plant is not an affected EGU subject to the Proposed Rule 

because it was constructed with the express purpose of serving an industrial load, and only a 

small percentage of the total power generated at the facility is sold to a utility distribution 

system. Commenters said the Proposed Rule does not contemplate the unique attributes of an 

EGU that is not part of an interconnected grid, which further supports the exclusion of the TS 

Power Plant from the scope of this rulemaking. Commenters said only Building Block 1 could be 

applied to the operations of the TS Power Plant, but it is unreasonable to assume a 6% heat-rate 

improvement at a six-year old, highly efficient facility. Commenters said inclusion of the TS 

Power Plant in the final rule would result in the imposition of an unreasonable and technically 

infeasible emission limit in a manner that would require the premature closure of the facility and 

constitute an unconstitutional regulatory taking. Commenters requested that EPA expressly 

provide in the final rule that the TS Power Plant is not an "affected" EGU and should not be 

included in the rule's baseline calculations or in Nevada's Section 111(d) implementing plan.

Commenters stated that the TS Power Plant does not meet the proposed applicability criteria and 

must be excluded from the final rule because this plant was constructed for the express purpose 

of generating power for Newmont's mine sites in northern Nevada. Commenters believed that the 

entire premise of the proposed rule is the interconnected nature of the electrical grid, and 

commenters concluded that the proposed rule should not apply to an EGU whose purpose is to 

support industrial activities. Commenters requested that the final rule exclude the TS Power 

Plant from the calculation of the Nevada emission limit and clarify that the TS Power Plant 

should not be included in the Nevada plan as an affected EGU because the TS Power Plant was 

not constructed for the purpose of supplying more than one-third of its "potential electric output" 

to the grid.

Comment 222: NV - BSER

Response 222: 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:
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Commenters stated Newmont expended more than $600 million in constructing the TS Power 

Plant, in reliance on existing regulations, and to ensure a continued, reliable electricity supply for 

its operations. Commenters said TS Power Plant is a new facility and could not achieve the 6% 

heat rate improvement either alone, or when averaged with Nevada's remaining coal-fired EGUs. 

Commenters said the remaining Building Blocks are inapplicable to the TS Power Plant and 

therefore cannot constitute BSER for the facility; moreover, when applied statewide, application 

of the first two Building Blocks would result in closure of all of Nevada's coal-fired EGUs, 

including the TS Power Plant. Commenters said the cost of such a performance standard is per se 

unreasonable; moreover, the approximately $450 million in stranded assets resulting from forced 

early retirement of the TS Power Plant would result in an unconstitutional taking.

Comment 223: NV - BB1

Response 223: See section V.C. of the final rule preamble of the CPP for the EPA’s response to 

this comment and more information about Building Block 1.

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

Commenters stated the TS Power Plant is one of the newest coal-fired power plants in the 

country; as a new power plant, numerous efficiencies were incorporated into the design in order 

to achieve the lowest possible heat rate. Commenters said due to a number of factors, achieving 

the 6% improvement in heat rate as proposed by Building Block 1 for the TS Power Plant is 

considered unrealistic and unachievable. 

Commenters said the 6% heat rate improvement scenario is based largely on methods described 

in the S&L Report and incorporated in the GHG Abatement Measures TSD; specifically, EPA 

designated nine methods described by S&L as best practices, representing a 4% improvement 

and four additional methods designated as equipment upgrades with the potential for a 2% 

improvement in heat rate. Commenters said the majority of these methods simply are not 

applicable to the TS Power Plant. Commenters said of the various methods described by EPA as 

justification for the Building Block 1 heat rate improvement, the majority are not applicable to 

the TS Power Plant because (1) the proposed upgrade already has been incorporated into the 

design of the TS Power Plant; (2) as a new facility, age-related degradation of various 

components that would negatively impact heat rate has not occurred, making equipment 

replacements unnecessary; and (3) equipment designated for upgrades (i.e. wet scrubber, ESP) is 

not installed at the TS Power Plant because the facility uses other emission control technologies. 

Commenters said of the thirteen methods included in the EPA analysis, only one, installation of a 

neural network system, has the potential to be applied at the TS Power Plant. Commenters said 

the S&L report indicates that a neural network could improve heat rate by between 0% and 1.5%. 

Commenters said installation of a neural network - which based on industry experience involves 

a substantial learning curve and does not react consistently to different types of coal - at a cost of 

hundreds of thousands of dollars, for negligible (or even non-existent) heat rate improvements is 

simply not reasonable. 
235

Comment 224: NV - RE

Response 224: See section V.E. of the final rule preamble of the CPP for the EPA’s response to 

this comment and more information about Building Block 3.

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

Commenters stated the Nevada Agencies found that several RE facilities were excluded from the 

USEPA's calculations for Nevada's RE and emission rate goals. Commenters said based on data 

from NV Energy's 2012 RPS compliance report, 372,621 MWh of RE generation were excluded 

from the USEPA's calculations. Commenters said including this "missing RE generation," 

Nevada's total RE generation for 2012 was 3,359,251 MWh. Commenters said using this 

statewide total, the percent of exported RE is 23%, leaving 2,540,728 MWh of creditable RE. 

Commenters stated in order to determine Nevada's new RE goal assuming RECs can be used for 

compliance, the USEPA's methodology for calculating Nevada's RE goal was reviewed. 

Commenters said the Nevada Agencies found that the USEPA used the 2012 total RE generation 

reported under EIA Form-923 to calculate Nevada's RE goal. Commenters said the RE 

generation reported on this form is not accurate. Commenters said based on publicly available 

information on the power purchase agreements (PPAs) for a number of facilities in Nevada, 

800,523 MWh of RE in 2012 was generated for out-of-state use. Commenters said this 

constitutes 27% of the 2,968,630 MWh (Nevada's total RE generation) used to calculate 

Nevada's final (2029) RE and emission rate goals. 

Comment 225: NV - EE

Response 225: See section V.A. of the final rule preamble of the CPP for the EPA’s response to 

this comment and more information about Building Block 4.

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

Commenters stated Nevada's housing stock is new, limiting Nevada's ability to deploy energy 

efficiency measures. Commenters said Nevada has experienced its large growth primarily in the 

past 20 years and thus does not have significant housing stock that is old, inefficient, and ripe for 

energy efficiency measures. Commenters said to add some perspective, Nevada's population was 

only 285,278 in 1960; it grew to 1,201,833 in 1990 and more than doubled by 2010 to 2,700,551. 

Commenters said accordingly, Nevada's efforts at DSM are limited, in part, by the large amount 

of newer housing stock and the fact that Nevada must gain incremental efficiencies over 

relatively new units with new appliances. Commenters said the USEPA fails to account for this 

in its analysis.

Comment 226: NH - recommend using New Hampshire's 2020 RGGI base budget to calculate 

the RGGI regional total projected 2030 mass-based goal 
236

Response 226: See section VII. 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 New Hampshire's 2020 (the last year of the current RGGI program's annual 

2.5 percent cap reduction) base budget (i.e., allowance allocation) under RGGI is 4.08 million 

tons; a number that DES and the PUC believe may be more appropriately reflective as a goal 

than EPA's projected New Hampshire 2030 emissions of 3.64 million tons, determined as part of 

its goal computation. Commenters said EPA's proposed goal is based on the assumption that all 

existing fossil fuel-fired generation will be re-dispatched to natural gas combined cycle (NGCC) 

units with a capacity factor of 63 percent , projected 2030 gas-fired generation of 8.3 million 

MWh, and an emission rate of 878 lbs/MWh for those units. Commenters said because any 

potential new sources are covered under the RGGI cap, further reducing the 2020 base budget to 

EPA's 2030 goal represents significant additional reductions. Commenters recommended using 

New Hampshire's 2020 RGGI base budget to calculate the RGGI regional total projected 2030 

mass-based goal, rather than EPA's presumptive, mass-based goal after rate-to-mass translation.

Comment 227: NH - general goal comments

Response 227: For the EPA’s response to this comment, see the CO2 Emission Performance 

Rate and Goal Computation TSD for CPP Final Rule supporting the final CPP.

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

Commenters stated upon evaluation of the EPA's goal-setting methodology and computations, 

the commenters were concerned with the ability of New Hampshire to meet the proposed CO2 

emission rate of 486 pounds per net megawatt-hour (lb/MWh), given state-specific and EGUspecific considerations. Although the commenters will certainly continue to support the carbon 

reduction effort in New Hampshire, the stringency of the building blocks prescribed by the EPA 

create insurmountable challenges for the state.

Commenters stated due to the broad assumptions made by the EPA in all aspects of the goalsetting formula, in the absence of a regional approach, the commenters asserted that New 

Hampshire lacks the flexibility to derive a combination of building blocks that will meet the CPP 

goal while providing cost-effective and reliable energy to consumers. 

Comment 228: NH - BB1

Response 228: See section V.C. of the final rule preamble of the CPP for the EPA’s response to 

this comment and more information about Building Block 1.

The following are summaries of the specific public comments under this comment:
237

Commenters stated with respect to Building Block 1, significant heat rate improvements at the 

coal-fired Merrimack Station (New Hampshire's largest coal-fired plant) were accomplished 

prior to 2012; hence New Hampshire would receive no credit for such improvements under the 

current proposal. At this time, the commenters asserted that additional significant upgrades to 

this and other coal-fired plants in New Hampshire may be difficult to accomplish. Commenters

added, the current operating scenario of New Hampshire's coal-fired power plants (operating 

more like peaking units as opposed to base-loaded units under the current electricity markets in 

the Northeast) would likely diminish any potential efficiency gains.

Comment 229: NH - BB3 

Response 229: See section V.E. of the final rule preamble of the CPP for the EPA’s response to 

this comment and more information about Building Block 3.

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

Commenters had significant concerns with the individual state rate based 2030 goal (486 

lbs/MWh) proposed by EPA for New Hampshire, the fifth most stringent goal proposed in the 

entire country. Commenters said relative to the potential for additional renewable energy under 

Building Block #3, while Renewable Portfolio Standards (RPS) in other states may be a 

mechanism by which to drive investment solely in new renewable energy, New Hampshire's 

RPS not only established Classes I and II for new renewable energy, but also established Class 

III Existing Biomass and Class IV Existing Small Hydro because legislators wanted to not only 

provide an incentive for new renewables, but also to maintain existing renewables that are "at 

risk" of shutting down. Commenters said accordingly, existing small (< 5 MW) hydro generation 

in New Hampshire should be credited by EPA. Commenters said small dams have high ongoing 

maintenance costs; without incentives, these dams struggle to remain open and economically 

viable. Commenters said similarly, biomass-fired plants cannot compete with relatively lowerpriced natural gas-fired plants without a financial incentive and are at some risk of shutting 

down; nearly 85 percent of (1,172,587 out of 1,381,286 MWh), of New Hampshire's 2012 nonhydro renewable generation was from biomass. Commenters said in 2006, the Schiller Station 

coal-fired plant replaced one of its three 50 MW units with a biomass-fired unit; thus, EPA's 

projected growth of renewable generation in New Hampshire is likely over-estimated. 

Commenters said while New Hampshire does have an RPS, compliance in 2013 was met mostly 

by Alternative Compliance Payments rather than increases in in-state renewable generation. 

Commenters added, out-of-state sources have recently applied for and received eligibility to 

create New Hampshire Renewable Energy Certificates (RECs). Commenters said the 

"Alternative Renewable Energy Approach", as outlined in EPA Technical Support Document, 

based on technical and economic potential as proposed by EPA could and should be used for 

New Hampshire. 

Comment 230: NJ increasing NGCC utilization should count towards goal compliance. 
238

Response 230: See section VIII 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 New Jersey's interim and final goals under the rule proposal are 647 lb/MWh 

and 531 lb/MWh, respectively, while its average existing NGCC emission rate is 889 lb/MWh. 

Commenters said analysis provided by EPA in its application of building block 2 assumes that 

the affected NGCC fleet is utilized at a capacity factor of 39% and that redispatch at 

approximately 44% could displace all the coal and oil-fired generation in the state. Commenters

said while New Jersey expects the recent asymmetric trends in fossil generation to continue with 

approximately 5% of NGCC capacity equaling its coal and oil-fired generation, due to the higher 

emission rates of coal and oil-fired generation as compared to NGCC, displacing this remaining 

coal and oil-fired generation will contribute to compliance with New Jersey's goal, but only to 

that nominal degree because its interim and final emission rate goals are lower than its existing 

NGCC fleet emission rate. Commenters said in fact, under EPA's rule proposal, any additional 

utilization of New Jersey's existing affected NGCC fleet, beyond displacing coal and oil-fired 

generation, would have to be offset by sources with emission rates lower than the proposed 

goals. Commenters said this would lead to discouraging use of additional NGCC, which is 

contrary to EPA's support for NGCC and the national CO2 emissions reduction goal, and limits 

New Jersey compliance options to non-fossil generation. Commenters said this result holds true 

for even the most efficient new NGCC units representing the cleanest fossil-fueled generation 

today. 

Commenters said states that have interim and final goals above 908 lb/MWh can benefit from 

adding NGCC as a cost-effective compliance option, whereas states like New Jersey have their 

options limited to EE and RE. Commenters said significantly, EPA's NODA of October 28, 

2014, views RE and EE as displacing NGCC units and coal and oil-fired units, and could result 

in a reduction of use of existing NGCC in New Jersey by 80%. Commenters said by adopting a 

uniform national performance standard of 1,030 lb/MWh, states would be encouraged to fully 

exploit the use of NGCC. 

Comment 231: NJ - BB3 RE 

Response 231: See section V.E. of the final rule preamble of the CPP for the EPA’s response to 

this comment and more information about Building Block 3.

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

Commenters stated EPA's algorithm governing building block 3 results in an RE share for New 

Jersey that is not supported by underlying data or proper evaluation; this is not a realistic or a 

reasonable outcome. 

Commenters stated according to the study prepared by the National Renewable Energy Lab 

(NREL) evaluating individual RE technical potential, relied upon by EPA in its Alternative RE 

Approach TSD, New Jersey has an RE potential of 0.11%, relative to the nation as a whole; yet 
239

under EPA's proposed RE approach to BSER, New Jersey is assumed to generate 2% of the 

national total of renewable generation, or approximately 18 times its technical potential for instate renewables. Commenters said this unbalanced proportion of RE results in an expectation of 

emission reductions that is unreasonable from both a technical and economic perspective. 

Commenters said New Jersey supports renewables through one of the nation's most aggressive 

RPS and New Jersey has developed more of its in-state solar technical potential than any other 

state in the nation. Commenters said EPA, however, improperly relies on a state's RPS to infer 

both technical and economic potential; such an approach penalizes states such as New Jersey that 

have taken early action to develop RE. Commenters said EPA must take a more pragmatic 

approach to this building block and evaluate state RE resource potential relative to both costs and 

environmental factors. Commenters said EPA's alternative RE approach to building block 3, is 

an appropriate starting point for EPA to reconsider the RE goal setting procedure. 

Commenters supported EPA's decision to not include Oyster Creek in the nuclear component of 

the goal since the unit is scheduled for retirement in 2019; however, EPA did not indicate 

whether the generation lost by this retirement would be replaced by new or existing units. 

Commenters said EPA must conclude that the lost generation will be replaced by existing fossil 

fuel-fired units and New Jersey's goal should be adjusted accordingly.

Comment 232: NJ -The EPA should modify its BSER methodology and adjust goal for New 

Jersey 

Response 232: See section V.A. of the final rule preamble of the CPP and the CO2 Emission 

Performance Rate and Goal Computation TSD for CPP Final Rule supporting the final CPP for 

the EPA’s response to this comment.

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

Commenters stated notwithstanding New Jersey's recommendation that EPA evaluate the merits 

of a uniform national performance goal, EPA must at least modify the four building blocks as 

detailed in the "New Jersey Corrective Approaches," provided below. Commenters said each 

Corrective Approach is independently justified and merits an adjustment to New Jersey's statespecific goal. Commenters said when combined, these corrections would significantly change the 

goal for New Jersey. 

1) New Jersey Corrective Approach 1: EPA's assumed re-dispatch of all coal and oil generation 

to NGCC must be modified. Commenters stated New Jersey evaluated how the State's goals 

would differ if EPA's assumed re-dispatch of coal and oil-fired generation to NGCC generation 

were modified. Commenters said in the proposal, New Jersey's goals are based on the assumed 

re-dispatch of 100% of the 2012 coal and oil-fired generation from the affected EGUs to NGCC. 

Commenters said this approach is fundamentally unsound because a 100% coal and oil-fired 

generation re-dispatch resulted in an increase in New Jersey's NGCC generation capacity from 

39% to only 44%, well below EPA's assumed maximum NGCC utilization level of 70%. 

Commenters said EPA's assumption that all of the coal and oil-fired generation can be redispatched to NGCC is not feasible because a minimum level of coal and oil-fired generation 
240

must be preserved in order to maintain grid reliability in the event of insufficient supplies of 

natural gas, most likely to occur during extreme weather conditions, as experienced during the 

winter of 2013-2014 and the polar vortex. 

Commenters said New Jersey re-calculated interim (2020-2029) and final (2030 and after) goals 

if EPA's unsound assumptions are relaxed (i.e., 100% of the coal and oil-fired generation is 

unlikely to be re-dispatched as NGCC). Commenters said these calculations were performed for 

both the 2012 base year (EPA proposal) and 2011 base year scenarios. Commenters said EPA 

eGRID data for 2011 was downloaded following the instructions provided by the EPA NODA. 

Commenters said the affected facility data for this year was used to calculate the interim and 

final goals for New Jersey using EPA's methodology provided in the Section 111(d) proposal. 

Commenters said with the exception of the base year data, all other aspects of the EPA goal 

calculation methodology, including the at-risk nuclear, renewable energy, and energy efficiency, 

were employed. Commenters stated for the no re-dispatch 2012 base year scenarios, New Jersey 

interim and final goals increased to 731 and 600 lb/MWh, respectively. Commenters said for the 

no re-dispatch 2011 base year scenarios, New Jersey interim and final goals increased to 797 and 

670 lb/MWh, respectively. Commenters said since 100% redispatch of coal and oil-fired 

generation from affected facilities is unreasonable for New Jersey, the higher 2012 baseline goals 

of 731 lb/MWh (interim) and 600 lb/MWh (final), at a minimum, should be considered; 

however, since 2011 was a more typical year for annual coal and oil-fired generation by New 

Jersey's affected EGU's, the higher 2011 baseline goals of 797 lb/MWh (interim) and 670 

lb/MWh (final), are more appropriate. 

2) New Jersey Corrective Approach 2: Different base years should be available to states to 

calculate goals. Commentersstated while EPA uses a single base year to set goals, providing 

states with flexibility in selecting the average of two years out of five or ten recent years would 

be consistent with the contemporaneous concept in EPA's New Source Review rules. 

Commenters said New Jersey conducted an evaluation of the New Jersey interim goal (2020-

2029) and final goal (2030 and after) and how these goals would change if a base year other than 

2012 were used. Commenters said the 2012 baseline year chosen by EPA was an atypical year 

for the operation of New Jersey's affected EGUs. Commenters said in 2012, the total generation 

from New Jersey's 21 affected EGUs was 25,087,907 MWh, which is significantly lower than 

the annual generation from these EGUs for the years 2010 and 2011 (27,806,585 and 30,302,427 

MWh, respectively). Commenters said use of multiple recent base years results is more 

representative of operations for New Jersey's affected EGUs and use of such typical years results 

in more reasonable interim and final goals. Commenters said EPA eGRID data for 2010 and 

2011 were downloaded following the instructions provided by the EPA NODA; the affected 

EGU data for these years were used to calculate the interim and final goals for New Jersey using 

EPA's methodology provided in the Section 111(d) rule proposal. Commenters said with the 

exception of the base year data, all other aspects of the EPA goal calculation methodology, 

including the at-risk nuclear, renewable energy, and energy efficiency, were employed. 

Commenters said the New Jersey interim and final goals increased to 661 and 550 lb/MWh, 

respectively, for the 2010 base year. Commenters said the New Jersey interim and final goals 

increased to 661 and 557 lb/MWh, respectively, for the 2011 base year. Commenters said if an 

average of the 2 years were assumed, New Jersey's goals would be raised to 661 lb/MWH 

(interim 2020-2029) and 553 lb/MWh (final 2030 and after), which would be more 

representative of the operation of those facilities than the use of the atypical 2012 values. 
241

3) New Jersey Corrective Approach 3: RPS growth rates should be based on retail sales RPS 

weighted averages and not the simple state averages used by EPA. Commenters said EPA has 

calculated individual state RE target levels through a series of steps that start by grouping 

individual state RPS 2020 percentage targets into regional averages. Commenters said each 

regional average was determined by simply averaging the respective RPS percent generation 

state targets for that region. Commenters said for example, the RE target for the East Central 

region is calculated as the average of 2020 RPS requirements in Delaware (19%), District of 

Columbia (20%), Maryland (18%), New Jersey (22%), Ohio (9%), Pennsylvania (8%), Virginia 

(N/A), and West Virginia (N/A), which is equivalent to 16% (Virginia and West Virginia are 

excluded from this calculation). Commenters said these regional percent averages are used in 

determining a state's RE MWh or, equivalently, its percentage target in Building Block 3. 

Commenters said state RPS requirements are typically determined by multiplying the RPS 

percentage for a particular year with the retail sales for that same year and, therefore, EPA must 

amend their methodology by applying a "weighted average" based on state retail sales. 

Commenters said regional RE targets would then be computed consistent with the weighted 

average RPS targets; the steps of this RE methodology are as follows: 

Step 1: Determine State 2012 retail sales using EIA data; 

Step 2: Multiply State 2020 RPS targets by its 2012 retail sales; 

Step 3: Determine regional RE MWh targets from Step 2; 

Step 4: Determine regional RE percentage targets from Step 3; 

Step 5: Recalculate State RE targets under Building Block 3; 

Step 6: Recalculate State goals. 

Commenters said under this approach, New Jersey's proposed interim goal (2020-2029) and final 

goal (2030 and after) have been recalculated; 663 lb/MWh and 561 lb/MWh, respectively. 

Commenters said under EPA's Alternative State Goals, New Jersey's interim goal (2020-2024) 

and final goal (2025 and after) have been recalculated; 731 lb/MWh and 690 lb/MWh, 

respectively. Commenters said this corrective approach, combined with the other corrective 

approaches, should be used by EPA to revise the goals for New Jersey. 

4) New Jersey Corrective Approach 4: EPA's Alternative RE Approach. Commenters stated 

while RE should not be used to set goals, the commenters supported EPA's alternative RE 

approach. Commenters said 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 said 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

said load serving entities (LSEs) are required to offset the electricity sold in New Jersey from 

qualifying renewables within the PJM region. Commenters said 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 said between 

2006 and 2010, 75% of the RECs retired for New Jersey's RPS program have come from out-ofstate renewables. Commenters said according to the National Renewable Energy Lab (NREL), 
242

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 said 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 said EPA must therefore base New Jersey's goal on the Alternative RE Approach if 

RE is ultimately used in goal calculations. Commenters said New Jersey's proposed interim 

(2020-2029) and final goals (2030 and after) have been recalculated; 724 lb/MWh and 668 

lb/MWh, respectively. Commenters said under EPA's Alternative State Goals, New Jersey's 

interim goal (2020-2024) and final goal (2025 and after) have been recalculated; 770 lb/MWh 

and 747 lb/MWh, respectively. 

5) New Jersey Corrective Approach 5: Use New Jersey's EE Market Potential Assessment Study 

Approach to establish EE targets instead of EPA's single target for all states. Commenters stated 

while EE should not be used to set goals for fossil fuel EGUs, adjustment of the EE component 

is appropriate to accommodate states that have advanced EE programs. Commenters stated New 

Jersey, like other states, develops and implements their EE and RE programs based on statewide 

market assessments, impact evaluations, or evaluations of other state market assessments in the 

region. Commenters said New Jersey has performed EE and RE market assessments to assist in 

developing the NJCEP programs. Commenters said despite the significant level of financial 

support by the New Jersey ratepayers for clean energy, including both EE and RE, New Jersey's 

Clean Energy Program has not achieved or approached the annual EE saving level of 1.5%. 

From 2004 to 2013, the annual energy savings from New Jersey's Clean Energy Program has 

ranged from 0.15% to 0.6%; this is, at best, 60% less than the annual EE savings goal set by 

EPA. Commenters said it is also significantly less than the estimates set in the NJCEP EE 

Market Assessment studies.

Commenters stated the maturity of the EE programs also has a major influence on energy 

savings. Commenters said as an established EE program develops, most of the no cost or low 

cost (low hanging fruit) is exhausted; the remaining EE savings, therefore, becomes more costly 

to acquire. Commenters said these programs require more complex administration to address 

various levels of incentives, financing and tiered rebates; this increases the EE program 

administration costs and greatly increases the dollars spent relative to the energy saved. 

Commenters said New Jersey's Clean Energy Program for EE and RE is a statewide program 

administered by the NJBPU. Commenters said it is not just one or two utility areas or one 

managed by one or two electric or gas utilities in various franchise areas; it is a statewide electric 

and natural gas EE and RE program. Commenters said the EE incentive and rebates offers are 

the same for Cape May Point (the southernmost point of New Jersey) to High Point (the northern 

most point of New Jersey). Commenters said this has an impact on an EE savings that can be 

achieved in New Jersey versus a state with a new EE program in just one utility franchise area 

that has a more specific focused approach to address one electric generation plant. 

Commenters stated the energy building codes also impact savings. Commenters said in New 

Jersey's program, as in most EE programs, the energy savings are calculated as the difference 

between the energy efficiency equipment and the energy building code requirement for that 

equipment. Commenters said as the energy building codes improves the energy efficiency that is 
243

required to be installed in new and retrofit construction, the energy savings an EE program can 

claim is getting smaller and smaller. Commenters said the cost to acquire these savings is also 

increasing. Commenters said some states calculate the energy savings based on the difference 

between the energy efficient equipment to be installed and the efficiency of the unit it is 

replacing; however, that requires a more complex measurement and verification method than the 

deemed energy savings calculation method currently used by the NJCEP and other state EE 

programs. Commenters said this increases the program administration costs and reduces the 

dollars available for EE direct incentives.

Commenters stated EPA must factor in the difference between projected and estimated EE 

savings and the actual reported savings in mature statewide EE programs; rather than regulate EE 

and RE under Section 111(d), the federal government should consider incentives and different 

regulatory authority to increase EE and RE. Commenters said the Best Practice Level of 

Performance was partly influenced by averaging recent electric EE potential studies, including a 

recent study conducted on behalf of New Jersey; this Study identified 0.8% as achievable and, 

therefore, EPA must adjust Building Block 4 to reflect NJ's achievable electric EE for both 

Option 1 and Option 2 if EE is to be included in goal determination. Commenters said replicating 

EPA's methodology for calculating savings target scenarios under Option 1 and Option 2 using 

0.8%, New Jersey's Cumulative Annual Electricity Savings (percentage of annual sales) under 

Option 1 and Option 2, result in 5.95% in 2029 and 3.44% in 2024, respectively. Commenters

said New Jersey's proposed interim goal (2020-2029) and final goal (2030 and after) have been 

recalculated; 663 lb/MWh and 560 lb/MWh, respectively; under EPA's Alternative State Goals, 

New Jersey's interim goal (2020-2024) and final goal (2025 and after) have been recalculated; 

723 lb/MWh and 680 lb/MWh, respectively. Commenters said this corrective approach, 

combined with the other corrective approaches, should be used by EPA to revise the goals for 

New Jersey. 

6) New Jersey Corrective Approach 6: Combination of Corrective Approaches. Commenters

stated EPA should evaluate all possible permutations of the Corrective Approaches presented. 

Commenters provided an example of a permutation by combining New Jersey Corrective 

Approaches 4 and 5; under this approach, New Jersey's proposed interim goal (2020-2029) and 

final goal (2030 and after) have been recalculated; 746 lb/MWh and 715 lb/MWh, 

respectively; under EPA's Alternative State Goals, New Jersey's interim goal (2020-2024) and 

final goal (2025 and after) have been recalculated; 772 lb/MWh and 752 lb/MWh, respectively. 

Commenters said this corrective approach, combined with the other corrective approaches, 

should be used by EPA to revise the goals for New Jersey. 

Commenters stated the coal-fired EGUs did co-fire with natural gas (most notably at Hudson 

Unit 2); given the amount of natural gas fired at our three coal-fired steam units the coal 

emission rate for New Jersey calculated by EPA is not a true emission rate for coal-fired 

generation only. Commenters said in the spreadsheet titled "tsd-plant-level-data-unit-levelinventory", EPA included all of the CO2 emissions and net generation from PSEG's coal-fired 

EGUs in 2012 regardless of the fuel burned at the time. Commenters said the inclusion of natural 

gas co-firing in the coal emission rate puts the New Jersey coal EGUs at a disadvantage because 

EPA is seeking an additional six percent heat rate improvement on units that have lower 
244

emission rates because of this co-firing; therefore, EPA must recalculate New Jersey's coal 

emission rate based on the hours when the units fired coal only and then apply the proper heat 

rate improvement target to this value. 

Comment 233: NM - coal retirements

Response 233: See section V.C. of the final rule preamble of the CPP for the EPA’s response to 

this comment and more information about Building Block 1.

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

Commenters stated EPA has publicly and repeatedly affirmed that coal-fired unit retirements can 

be part of a state's compliance plan under EPA's Section 111(d) Clean Power Plan proposal; 

although EPA's preamble, goal calculations, and technical support documents are consistent with 

that understanding, an express confirmation of that approach would help avoid any potential 

challenges during the SIP development and approval process. Commenters said EPA should 

expressly confirm that the retirement of two coal-fired electric generating units in New Mexico, 

which will reduce annual CO2 emissions by 36 percent, will count towards compliance with 

EPA's proposed Clean Power Plan; specifically, EPA should affirm that those retirements should 

not be assumed in calculating the New Mexico goals, but should be reflected in the compliance 

calculations. 

Commenters stated EPA should expressly and unambiguously confirm that the retirement of San 

Juan Units 2 and 3 by December 2017 will help New Mexico comply with the emission rate 

goals that EPA has proposed through both ensuring that the goal calculation does not already 

assume those reductions in defining the goal and through allowing those reductions to be 

included in the compliance calculation. 

Commenters stated although primarily intended to facilitate compliance with the Clean Air Act 

regional haze program, the retirement of two of New Mexico's largest coal-fired units by 

December 31, 2017 will have a dramatic impact on CO2 emissions in the State. Commenters

said since San Juan Unit 2 emits approximately 3.1 million tons of CO2 per year and San Juan 

Unit 3 emits approximately 4.6 million tons per year, the retirement of those units will eliminate 

7.7 million tons of CO2 emissions annually. Commenters said that reduction in annual emissions 

will reduce New Mexico's overall CO2 emission rates by 21 percent on a lb/MWh basis, and 

reduce the State's CO2 mass emission rates by 36 percent in total tons of emissions (based on 

expected emissions in 2014). 

Commenters stated based on the manner in which EPA calculated the CO2 emission rate goals 

for New Mexico, EPA appears to have recognized the significant progress towards a lowercarbon future that these coal-fired unit retirements will make; specifically, in calculating the 

emission reduction goals for New Mexico, EPA began with the 2012 CO2 emissions from San 

Juan Units 2 and 3 in the numerator of the equation and included 2012 generation from those 

units in the denominator of the equation, before applying the various building blocks; therefore, 

assuming that EPA will allow New Mexico to use the same calculation method to demonstrate 

compliance that EPA used in establishing the goal, the compliance demonstration calculation 
245

will reflect the retirement of those units after 2017 because the numerator will no longer contain 

any CO2 emissions from the retired units. Commenters said while the denominator will also 

decrease, the overall effect of the retirement of San Juan Units 2 and 3 will be to eliminate a 

higher-carbon-intensity resource; thus, based on EPA's proposed goal calculation, the retirement 

of San Juan Units 2 and 3 will help New Mexico reach its goals. 

Comment 234: NM - BB1 HRI

Response 234: See section V.C. of the final rule preamble of the CPP for the EPA’s response to 

this comment and more information about Building Block 1.

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

Commenters stated EPA's decision to apply its generic, hypothetical six percent assumption is 

particularly inappropriate for New Mexico because New Mexico's largest coal-fired facility, San 

Juan, which accounts for nearly 90 percent of the coal-fired generation in the State, has already 

made significant efficiency improvements for which it would not receive any credit under EPA's 

proposal. Specifically, commenters stated San Juan has already implemented many of the 

projects referenced in EPA's GHG Abatement Measures Technical Support Document or similar 

projects, including the following: 

• Replaced pulverizer classifiers to improve coal fineness 

• Installed rotating air throats on pulverizers to improve coal fineness 

• Replaced various portions or sections of boiler tubes 

• Replaced air foils with flow nozzles, improving air flow accuracy and combustion 

efficiency 

• Installed neural network to optimize combustion controls 

• Installed new air heater seals 

• Baghouse installations to replace electrostatic precipitators (ESPs) 

• Burner replacement 

• Replaced portions of piping and headers with advanced designs and materials 

• Replaced the venturi throat on FGD systems 

• Boiler cleaning to remove boiler scale 

• Turbine overhaul to replace turbine rotor, inner shell, diaphragms, and 

packing/seals 
246

• Feedwater heater tube replacement 

• Installed advanced cooling tower fill, replaced cooling tower fill and grid, tuned 

cooling tower 

• Cleaned condenser tubing 

• Replaced older electric motors with new, more energy efficient motors 

Commenters stated that San Juan estimates that, from 2006 (before most of these projects were 

completed) to 2013 (after all of them were completed), the heat rate improved at two units, but 

did not improve at the other two units; over the time period during which these projects were 

performed, the overall plant-wide heat rate improvement was just over one percent. Commenters

said despite these significant efforts to improve efficiency, no significant trend in heat rate can be 

discerned.

Commenters stated even though PNM has already undertaken most of the efficiency projects that 

EPA recommended in its building block 1 analysis, EPA assumes that San Juan is nevertheless 

capable of achieving just as much of an efficiency improvement as a theoretical generator that 

has only taken advantage of half of those projects, according to the generic assumption EPA has 

applied nationwide. Commenters said because the improvements San Juan has already made 

were completed prior to the EPA-selected baseline of 2012, they will not count toward 

compliance with New Mexico's emission rate reduction goals; therefore, EPA's building block 1 

assumes that San Juan must achieve another six percent improvement, above and beyond the 

improvements already achieved. However, commenters stated, due to the efforts San Juan has 

already made, plant engineers do not expect that efficiency can be improved by any more than 1-

2 percent beyond current efficiency levels, well below the additional six percent EPA assumes to 

be hypothetically achievable. 

Commenters stated the 2012 baseline initially chosen by EPA actually represents the best heat 

rate for two of the San Juan units, and one of the lowest heat rates for the other two units. 

Commenters stated as a result, the heat rate EPA expects San Juan to achieve is actually six 

percent better than the level it achieved in one of its best-performing years. Therefore, in order 

for San Juan to achieve the heat rates EPA expects in all years, including those that will be 

inevitably higher due to uncontrollable variability in efficiency levels, the commenters said PNM 

may have to achieve an even greater efficiency improvement than six percent.

Commenters stated like many units across the country, San Juan is facing new environmental 

requirements for conventional pollutants that will make achieving additional efficiency 

improvements more difficult by increasing the parasitic load that the unit itself will need to 

operate those new controls. Commenters said San Juan is likely better off than many units in the 

country because it has already installed a suite of state-of-the-art controls that many other units 

may still need in order to comply with other EPA requirements, including scrubbers, baghouses, 

low NOx burners; but even the well-controlled San Juan units will still need to install additional 

systems in the near future to comply with new EPA rules that could impact efficiency levels, 

such as the Selective Non-catalytic Reduction (SNCR) systems imposed under the regional haze 

program, which could increase the parasitic load at the plant by up to 2 MW per unit. 
247

Commenters stated as a result of the efficiency improvements PNM has already achieved at San 

Juan, and the additional environmental controls that will reduce efficiency and make additional 

improvements even more difficult, the commenters believe that the additional six percent heat 

rate improvement that EPA expects under building block 1 for New Mexico is not feasible for 

San Juan. Therefore, commenters stated EPA's assumptions for building block 1 are likely 

unachievable for the State as a whole, given that San Juan represents the vast majority of coalfired generation in New Mexico. Accordingly, commenters asked EPA to revise its nationwide 

building block 1 assumptions for states like New Mexico, where they are inappropriate. 

Comment 235: NM - BB2

Response 235: See section V.D. of the final rule preamble of the CPP for the EPA’s response to 

this comment and more information about Building Block 2.

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

Commenters stated partial re-dispatch is possible in New Mexico; it may, therefore, become an 

important option to include in the New Mexico State Plan.

Comment 236: NM - BB4 EE

Response 236: See section V.A. of the final rule preamble of the CPP for the EPA’s response to 

this comment and more information about Building Block 4.

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

Commenters stated they generally support EPA's recognition of the importance of energy 

efficiency (EE) in reducing CO2 emissions. However, commenters stated they have a number of 

concerns regarding EPA's methodology and assumptions underlying the use of EE savings in 

calculating the proposed state goals for New Mexico:

1. Commenters questioned EPA's decision to assume the same annual savings rate of 1.5 

percent is achievable in all states. Commenters said that assumption is based on the 

historical savings rate that has been achieved in only three states with the most aggressive 

EE programs (Maine, Vermont, and Arizona) and is not an appropriate target for all states 

because energy use per customer varies significantly from state to state and can have a 

significant impact on the cost-effectiveness of many EE programs; specifically, states 

with low electric energy use per capita may not be able to achieve the same savings rate 

as states with higher energy use per capita. Commenters said residential users in New 

Mexico likely have less opportunity for energy savings than customers in other states 

with higher per capita energy usage rates. Commenters added many typical EE programs 

are also less cost-effective in New Mexico, due to the mild climate in the 

area. Commenters said cannot seek approval of EE measures that are not cost-effective, 
248

thus have fewer options available to it in meeting EPA's EE expectations than other 

utilities in other states. 

2. Commenters questioned EPA's assumption that a savings rate of 1.5% can be sustained 

indefinitely, year after year. Commenters said recent EE successes relied upon by EPA in 

developing its building block 4 assumptions have depended upon the benefits provided 

by lighting retrofits -the replacement of incandescent bulbs with LED bulbs or other 

efficient lighting technologies- which provide an extremely cost-effective and universal 

means of improving EE across all sectors of the economy. However, commenters stated

once LED and other lighting technologies have saturated the market, which is likely to 

occur in the next ten years, additional efficiency improvements will require more 

aggressive, and less cost-effective, actions that will likely result in smaller and smaller 

efficiency improvements. Commenters recommended that EPA recognize the fact that 

savings rates cannot be sustained indefinitely in defining its expectations for efficiency 

improvements under building block 4. 

3. Commenters said EPA's 1.5 percent one-size-fits-all goal for states fails to take into 

account the variation in demographics in different states that could have a significant 

impact on the potential success of EE programs. Commenters added that in particular, 

New Mexico has a significant rural population, and participation in EE programs is 

typically low in rural populations. In addition, the commenters stated New Mexico has a 

very low income per capita, which suggests many New Mexico residents will not have 

sufficient resources to participate in EE programs unless they are fully funded upfront by 

the utility, which generally makes those programs less cost-effective. Commenters said 

EPA should take these state-specific barriers to EE programs into account in developing 

its assumptions regarding the level of EE improvement that will be achievable in New 

Mexico. 

4. Commenters asked EPA to reconsider its decision to ignore savings resulting from EE 

programs prior to 2017 and only count post-2017 improvements in EE toward 

compliance with each state's emission rate reduction goals. Commenters said although 

states without significant existing EE programs will need time to develop and implement 

new programs, and therefore should not be required to comply prior to 2017, states that 

already maintain EE programs should be able to count the savings realized from those 

programs even if the savings occur prior to 2017. Commenters recommended that EPA 

allow all net EE savings that have been achieved from utility implemented programs, or 

at least those that have been implemented in the ten years before 2017. 

5. Commenters said EPA should take each state's prior experience with EE programs into 

account in determining what is achievable in the state. Commenters stated New Mexico 

began requiring utilities to implement EE programs in 2005 with the Efficient Use of 

Energy Act (EUEA), which established cumulative EE savings goals of 5 percent and 8 

percent by 2014 and 2020, respectively (below 2005 levels). Commenters said with their 

initial efforts, New Mexico utilities should have been able to take advantage of the most 

cost-effective measures available (e.g., LED lighting), but even so at least one utility has 

already indicated that it will not be able to meet the EUEA goals, despite implementing 

numerous programs that were projected to achieve those goals. Commenters said given
249

that meeting the EUEA goals have already proven difficult for one utility, and the fact 

that EPA's goals are far more aggressive than the EUEA (seeking a 10.6 percent 

improvement over 2012 levels by 2030), EPA should reconsider its assumptions 

regarding the level of EE that will be achievable in New Mexico. Commenters added the 

EUEA requires New Mexico utilities to ensure their EE programs are cost-effective based 

on a "utility cost test" which ensures that "the monetary costs that are borne by the public 

utility and that are incurred to develop, acquire and operate energy efficiency or load 

management resources on a life-cycle basis are less than the avoided monetary costs 

associated with developing, acquiring and operating the associated supply-side 

resources." Commenters said like New Mexico's RPS, the EUEA also restricts New 

Mexico utilities from spending more than 3 percent of sales on EE programs. 

Commenters supported EPA's decision to recognize states' EE efforts generally, but asked EPA 

to consider allowing the State of New Mexico to establish its own EE targets based on its 

understanding of the state-specific constraints that EPA's analysis fails to address. Alternatively, 

the commenters asked EPA to reconsider its EE targets by taking those constraints into account 

on a state-by-state basis. 

Comment 237: NM - impacts of CPP

Response 237: For the EPA’s response to this comment, see the CO2 Emission Performance 

Rate and Goal Computation TSD for CPP Final Rule supporting the final CPP.

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

Commenters stated developed a computer model to analyze aspects of the proposal and 

determine the potential impacts on New Mexico of various policy choices selected by EPA in 

developing the proposed Clean Power Plan. Commenters said the model provides a current 

forecast of expected annual generation and CO2 emissions from existing fossil fuel-fired 

generating units for the compliance period of 2013-2030-referred to as a "base case"-and 

compares that forecast to EPA's proposed emission reduction goals to evaluate the "compliance 

gap" that will exist between the EPA's proposal and New Mexico's projected emissions rate. 

Commenters stated the "base case" analysis indicates that, despite New Mexico's already 

aggressive plans to reduce CO2 emissions-including the retirement of two of the largest emitting 

sources in 2017 and the significant increases in renewable energy and energy efficiency expected 

in future years under existing federal and state laws-a significant compliance gap of 211 lb/MWh 

remains between EPA's goal of 1,0481b/MWh and New Mexico's projected "base case" rate of 

1,259 lb/MWh. 

Commenters stated in addition to illustrating the "compliance gap" that will remain under the 

"base case" in New Mexico, the model allows the various parameters to be altered to illustrate 

the potential impact that any changes in policy will likely have on the goals for New Mexico and 

the ability of the State to meet those goals. Commenters said by altering some of the assumptions 

EPA used to develop its proposed goals, the model can illustrate the effect that alternative 

policies will have on New Mexico's compliance gap. 
250

Commenters stated that deliberations for the final rule should include re-evaluation and 

clarifications of the list of affected sources within New Mexico because the State Goal 

Computation Technical Support Document provided in the docket does not include all affected 

sources and may include some sources that do not meet proposed applicability criteria.

Comment 238: NY credit for early action should be given; NY already making reductions

Response 238: See sections VI., VIII.B., and VIII.C. 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 New York has already reduced CO2 emissions from its power sector by 

41.6% below 2005 levels and generates approximately 53% of the electricity it uses on an annual 

basis from non-emitting resources. Commenters said the state's generation fleet is the ninth 

cleanest in the country, and New York's commitment to the Regional Greenhouse Gas Initiative 

(RGGI) calls for even further CO2 reductions between now and 2020. Commenters said New 

Yorkers currently pay the highest electric rates in the contiguous United States, including fees 

that are used to fund investments in clean energy and conservation that have contributed to New 

York's already low-carbon emissions profile. Commenters said the targets developed for New 

York under the Clean Power Plan for further CO2 emissions reductions should recognize and 

appropriately reflect the significant efforts that have already been made in New York and the 

progress that has been achieved.

Commenters stated a legitimate program should not punish States that have made significant 

progress to addressing GHG. Commenters said the EPA should commend States that have made 

significant GHG reductions on their own; there is little doubt that New York is treated 

inequitably. Commenters said compounding the issues with inequitable treatment is the fact that 

New York has some of the United States' highest energy cost and cannot sustain any increased 

energy costs. Commenters stated other States need to address the economical low hanging fruit; 

national policy should be focused on reducing national GHG in a manner that first address the 

least costly options.

Commenters stated New York City has been a leader in addressing climate change at the local 

level and is working both to reduce our own contributions to global warming and to prepare for 

its inevitable effects. Commenters said this work is occurring as part of PlaNYC, an integrated 

sustainability plan for a greener, greater New York by the year 2030. Commenters said as part of 

that effort, New York City recently set an ambitious goal to reduce citywide GHG emissions by 

80 percent below 2005 levels by the year 2050, representing the same goal set by the United 

Nations' Framework on Climate Change to prevent dangerous anthropogenic interference with 

the climate system. Commenters said in just seven years, the City has reduced emissions from 

municipal buildings and City operations by 19 percent; moreover, the City is on track to meet the 

goal of a 30 percent reduction in City government emissions by 2017. Commenters said more 

than 65 percent of these citywide GHG emissions reductions are attributable to fuel switching 

and other improvements in the City's electric and steam generation facilities.
251

Commenters stated the City is acting to develop a cleaner power sector; in addition to the 

planned 100 megawatts of renewable generating capacity that the City intends to install, it is 

considering incentives geared toward private-sector development of renewable generation 

capacity and is working with the State on measures that would support the proliferation of noncarbon based generation. Commenters added the City has secured a license from the Federal 

Energy Regulatory Commission to build a 14 megawatt hydroelectric facility at the Cannonsville 

Reservoir, a component of the City's drinking water supply system, and it recently entered into 

an agreement with a private developer for a large-scale solar installation at its Fresh Kills 

landfill.

Comment 239: NY - general goals

Response 239: For the EPA’s response to this comment, see the CO2 Emission Performance 

Rate and Goal Computation TSD for CPP Final Rule supporting the final CPP.

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

Commenters stated the size of reduction for New York State under the EPA's Plan is large when 

compared to other states, especially given the amount of emission reductions already achieved by 

the state and the anomalous 2012 baseline. Commenters said New York State remains at a 

competitive disadvantage when compared to other states that have reduced their respective CO2 

emissions less than the state already has. Commenters said the EPA's Plan, and New York's 

implementation of it, should not have the outcome of driving out of New York State additional 

manufacturing companies and other high energy users. Commenters said EPA's Plan needs to 

give credit to states with large consumer electricity costs given that New York's energy 

consumers already bear the cost of the achievement of emission reductions. Commenters said the 

EPA's Plan should have a balanced approach across states in terms of the overall national 

reduction in CO2 emissions. Commenters said New York State should not be penalized for being 

a leader and an early mover in terms of reducing the CO2 intensity of its electric power sector; 

other states must do more, as additional emission reduction opportunities exist. Commenters said 

New York State's emission reduction success to date shows that other states must be required to 

reduce their emissions more in relation to New York State. 

Comment 240: NY - BB2 

Response 240: See section V.D. of the final rule preamble of the CPP for the EPA’s response to 

this comment and more information about Building Block 2.

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

Commenters stated the CPP poses difficult challenges for New York in achieving the target CO2 

emission rate required by EPA's proposal. Commenters said these challenges arise, in part, 

because the State's prior efforts in reducing emissions have exhausted almost all of the emission 

reduction potential of one of the building blocks; thus, while the commenters understand that 
252

EPA is not requiring that the State implement each building block at the level contemplated in 

the proposal, New York has less flexibility and fewer strategies to deploy in meeting its target 

than many other states. 

Commenters stated Building Block Two's anticipated level of re-dispatch to existing NGCC 

plants is unattainable given reliability requirements that necessitate the operation of oil/gas steam 

units in New York City and Long Island, as well as other factors. Commenters said generation 

owners are subject to market and reliability rules that are approved by the Federal Energy 

Regulatory Commission (FERC). Commenters said the consequence of these FERC rules is that 

re-dispatch to NGCC units from other fossil fuel units, especially oil/gas steam units, is limited 

by an electric transmission and/or a gas supply constraint. Commenters said as a result, it is 

virtually impossible for New York to achieve the 70% capacity utilization assumed by EPA in 

Building Block Two.

Commenters stated EPA's application of Building Block Two to New York requires a 99.3% 

reduction in coal and oil-fired generation as a result of re-dispatch to natural gas; but, as 

explained by EPA, a "state's NGCC generation is only adjusted up to [the 70%] ceiling if its 

historic fossil sources support such a level." Commenters said because of constraints, New 

York's fossil sources do not support this level. Commenters said although New York supports 

switching from coal or oil to NGCC where feasible, New York's electricity system simply cannot 

accommodate this level of re- dispatch; therefore, the final CPP rule should address New York's 

unique circumstances and constraints regarding natural gas dispatch.

Commenters stated there are specific limitations unique to the ability of the New York 

Metropolitan Area (NYMA) that further limit the amount of "Other Gas" generation that can be 

displaced or redispatched in New York. Commenters said units located in New York City are 

required to run in order to provide needed voltage support and frequency stability in this heavilypopulated urban center; while unit upgrades and re-powering with natural gas have dramatically 

improved the emissions profile of "incity" generation over the past decade, the system cannot 

maintain stability and reliability without these key resources. 

Commenters stated an additional factor concerns the use of oil in these dual-fuel units; in order 

to protect reliable delivery of power during high natural gas use periods, whether during the peak 

summer time load period or winter periods when natural gas deliveries are constrained and 

preferentially routed to residential customers, NYISO rules require generators in the NYMA to 

combust oil in dual fuel units to ensure the reliable provision of electricity in the event of an 

unforeseen contingency on the natural gas transmission and delivery system. The commenters

said this requirement and its consequence for generation have previously been addressed by the 

EPA, particularly in its Cross State Air Pollution Rule ("CSAPR"). 

Comment 241: NY - BB3 RE

Response 241: See section V.E. of the final rule preamble of the CPP for the EPA’s response to 

this comment and more information about Building Block 3. Any on-the-way incremental RE 

capacity post 2012 levels would have its generation qualify for compliance purposes in the future 
253

compliance year in which that generation occurs. In this way, among others, early action is 

being recognized and compatible with CPP compliance.

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

Commenters stated the CPP poses difficult challenges for New York in achieving the target CO2 

emission rate required by EPA's proposal. The commenters said because it relies on Northeastern 

states' relatively ambitious renewable energy policy targets, Building Block Three sets an 

extremely challenging goal for the amount of renewable energy generation assumed to be 

achievable in New York. The commenters said this difficulty is exacerbated by EPA's 

disallowance of existing hydroelectric power to meet EPA's target even though it has included 

existing hydroelectric power in establishing the State's emission reduction target. The 

commenters said it has been New York's policy to promote the development of new renewable 

energy resources since at least 2004, when the PSC instituted the State's 2015 renewable 

portfolio standard (RPS) target to support over 14,000 GWh of renewable electricity purchases 

made through a variety of initiatives including the Main Tier, Customer-Sited Tier, Voluntary 

Market activity, Executive Order 111, and Long Island Power Authority (LIPA) contributions.

Commenters stated EPA has ignored key aspects of New York's RPS in its rate-setting formula. 

The commenters said part of the rationale behind setting New York's RPS at 30 percent of 

electric energy used in the State was that existing hydropower facilities would be counted toward 

attainment of that goal. The commenters said EPA has stripped existing hydropower out of New 

York's attainment, changing its effective renewable generation rate to 4 percent from 17 percent 

of energy generated. The commenters said EPA thereby requires the State to develop more than 

8,600 MW of additional renewable generation to meet EPA's final 18 percent target, as compared

to the 2,700 MW that would be required to meet the full 25 percent EPA target were existing 

hydropower to be counted. The commenters said as a result of the inconsistency in the ratesetting formula and the inequity in the regional rates, the commenters do believe that the 

proposal to allow regional compliance with the targets under this Building Block as put forth in 

the October 28th NODA, would resolve this concern.

Commenters stated nuclear, hydro, and other zero-emissions resources generated more than 53 

percent of the electric energy used in New York in 2013; as such, they are crucial to New York's 

emissions reductions efforts. The commenters said without these resources, New York would not 

have been able to achieve the significant emissions reductions it has seen over the past decade; 

ensuring these resources remain in place will be key to the State meeting future targets as well; 

indeed, the loss of any one of these resources may significantly increase fossil emissions in the 

State. 

Commenters stated several factors limit states' ability to govern the operation of these facilities -

particularly under the auspices of the Clean Air Act. The commenters said as zero-emissions 

resources, these plants are not directly regulated under the Act; the EPA has no authority to 

compel these resources to operate. The commenters said further, particularly in states with 

deregulated electricity markets, states are also restricted from providing out-of-market incentives 

to these resources by FERC rules. 
254

Commenters stated as it pertains to nuclear assets, licensing and supervision of these plants is the 

sole jurisdiction of the federal Nuclear Regulatory Commission (NRC); states who have sought 

decision-making authority with respect to nuclear plants within their borders have found 

themselves with few options to either incentivize the continued operation of, or advocate for the 

closure of, these units. 

Commenters stated in New York, particularly, the EPA has not included the generation 

associated with its existing large hydroelectric facilities as part of the zero-emission resource 

Building Block, reportedly because it "distorts" the adjusted emission rate for the State; in the 

same manner, emission-free nuclear generation, either in the numerator or the denominator of the 

adjusted emission rate, distorts the ability of the State to meet its adjusted emission rate target. 

The commenters suggested that eliminating nuclear generation from the adjusted emission rate 

calculation across all states would be an equitable way for states to allow power markets to select 

for emission-free generation technologies in cooperation with the NRC if nuclear generation is a 

preferred approach or in cooperation with other permitting entities if other technologies such as 

wind or solar are more cost-effective.

Comment 242: NY - flexibility issues

Response 242: See sections I.A., VI., VIII.B., and VIII.C. 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:

Early Actions

Commenters stated while the State understands EPA's proposal does not require states to 

implement each particular building block at the assumed levels, this apparent flexibility is 

limited in practice for a state like New York. The commenters said EPA's proposal offers a state 

flexibility to deviate from a particular building block only to the extent emission reductions may 

be made up through other building blocks or other means. The commenters said because of the 

ambitious level of EPA's proposed target and the fact the State has already achieved substantial 

emission reductions using the same strategies EPA incorporates in the building blocks, such 

"flexibility" is in reality limited. The commenters said as EPA explains in its proposal, the 

application of a building block to a state may be limited if a state demonstrates that it cannot 

achieve the anticipated level of emission reductions from the building block and cannot make up 

the emissions through application of other building blocks; this is precisely the situation for New 

York. The commenters said having already driven substantial change in the generation dispatch 

and the supply portfolio, the State would have to leverage additional reductions using a smaller 

tool box than that available to the less-advanced states. The commenters said EPA should make 

adjustments to three of the proposed building blocks; the commenters said refinements to 

Building Blocks Two, Three, and Four would more accurately reflect achievable and adequately 

demonstrated opportunities for emission reductions across the country.

Gas and Electric Systems
255

Commenters stated New York's existing gas and electric infrastructure does not enable 

achievement of this building block as structured by EPA. Commenters stated that while 

they understand that EPA's intent under the CPP is to apply all building blocks equally to all 

states, New York presents a special case, as Congress recognized in the Energy Policy Act of 

2005. The commenters said in particular, Congress recognized the unique nature of New York's 

reliability issues by singling out New York and specifically allowing the State to go beyond 

federal reliability standards. See 16 U.S.C. section 824o. The commenters said EPA previously 

recognized many of these constraints unique to the New York City and Long Island regions of 

the State when it revised the State's emission budgets under the Cross-State Air Pollution Rule 

(CSAPR) to account for the State's reliability issues. The commenters said consistent with the 

Clean Air Act's requirement that standards of performance consider "energy requirements," 42 

U.S.C. section 7411(a)(1), EPA should modify the CPP to similarly account for these New Yorkspecific constraints and reliability requirements. The commenters said in this way, this building 

block will require re-dispatch of existing coal and oil/gas steam units to the maximum extent that 

is realistically achievable. The commenters said EPA's proposal assumes that the output of 

NGCC across the country could be increased to displace the output of the more carbon-intense 

coal and oil and/or gas fired steam units. The commenters said its basis is that the nation's 

average NGCC fleet utilization rate or capacity factor using nameplate ratings is between 44% -

46%, while the NGCC's fleet's availability factor is between 87% - 92%. The commenters said 

the NGCC output increase envisioned in this building block is not realistic for New York, 

however, because it does not adequately consider the State's existing physical gas and electric 

system constraints. The commenters said New York cannot use this building block to obtain the 

operating output of NGCC units envisioned by EPA. 

Reliability Requirements 

Commenters stated to ensure electric system reliability, certain generators located in New York 

City and Long Island are required to comply with rules of the New York State Reliability 

Council (NYSRC) as implemented by the New York Independent System Operator, Inc. 

(NYISO). The commenters said these rules require, for example, that, under high load 

constraints, some higher-emitting oil/gas steam generating units be dispatched on oil to guard 

against potential interruption in gas supply to ensure electric reliability in these metropolitan 

areas. The commenters said as a result, specific units that would generally be uneconomic to 

dispatch are required to operate; moreover, because of the NYSRC Minimum Oil Burn 

requirements, some oil/gas steam units in New York City must operate using oil at certain times 

of the year, in order to be able to immediately switch operation and be prepared for a natural gas 

supply disruption. The commenters said taken together, these unique New York City and Long 

Island requirements constrain the NYISO's ability to dispatch NGCC units. The commenters said 

EPA has neglected to take any of these limitations into account when evaluating the potential 

reduction in New York achievable under Building Block Two, despite previously recognizing 

these constraints in its final CSAPR revisions. 

Comment 243: NC - general goal; BSER; credit for early action
256

Response 243: See sections VI., VIII.B., and VIII.C. of the final rule preamble of the CPP and 

the CO2 Emission Performance Rate and Goal Computation TSD for CPP Final Rule supporting 

the final CPP for the EPA’s response to this comment.

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

Commenters stated EPA has stated that there is flexibility in the rule in that it allows states to 

develop their own compliance plans; these compliance plans may, but are not required to, utilize 

any combination of the four "building blocks" identified in the proposed Clean Power Plan. The 

commenters were concerned that any purported flexibility is unfounded, and asks how flexibility 

can be achieved when EPA has already demonstrated that North Carolina will need to use all 

four building blocks to achieve an overall 44 percent reduction from the 2012 baseline CO2 rate 

of 1772 lb/MWh to a final rate of 992 lb/MWh. The commenters said it must be recognized that 

the proposed emission reduction goals for North Carolina cannot be achieved solely by insidethe-fence-line improvements at existing fossil fuel-fired EGUs, which is the only legal method to 

achieve these CO2 emission reductions. 

Commenters asserted that EPA unlawfully imposes a standard for affected, existing EGUs that is 

more stringent than the standard for new EGUs. The commenters said compared to North 

Carolina's mandatory interim goal of 1,077 lb/MWh and final goal of 992 lb/MWh, the proposed 

new source performance standard for a new coal unit is 1,000-1,050 lb/MWh and for a new gas 

unit is 1,100 lb/MWh. The commenters said EPA's logic implies that a new fossil unit in North 

Carolina, which can only be constructed using the absolute best control technology, requires a far 

less stringent compliance requirement than existing units. The commenters said there is no legal 

or rational basis to set North Carolina's mandatory goals for existing units below the standards 

required for new units; to remedy this flaw, the commenters requested that any carbon emission 

rate adopted for North Carolina must be higher than what is required for new units. 

Commenters stated the regulation would require the state of North Carolina to meet a proposed 

target of a 39% reduction of CO2 intensity by 2030; North Carolina has been a leader in 

reducing our carbon footprint. The commenters believed this aggressive target ignores 

NC's position as an early leader of policies that have led to a decrease in emissions. The 

commenters said by using a 2012 baseline data in the rule, EPA punishes North Carolina - a state 

that spent over $2 billion to comply with the Clean Smokestacks Act, retire over 3,400 MW of 

coal generation since 2002, and considers the potential cost of carbon emissions when making 

decisions about the generation portfolio. The commenters requested that the EPA revise its 

emission goals to more accurately reflect the progress North Carolina has made in reducing 

emissions at the great expense of both utilities and ratepayers.

Comment 244: NC - affected units (errors); existing units; under construction units; capacity

Response 244: As explained in section V of the final rule preamble of the CPP, nuclear is not 

part of the final rule CPP. As explained in the CO2 Emission Performance Rate and Goal 

Computation TSD for the CPP Final Rule, the EPA has revised its categorization of under 

construction units to treat units such as Dan and Lee that commenced operation in 2012 as under 
257

construction. The EPA also notes that building block assumptions are assumptions about the 

fleet-wide capability for a region, not an expectation that every unit can operate in that manner.

In this final rule, the EPA relies on net electric output. At proposal, the EPA was folding useful 

thermal output into the goal and the use of net energy output. Based on comments, the EPA no 

longer folds useful thermal output into its BSER quantification, but states are still permitted to 

use it when demonstrating compliance. The EPA followed the methodology as explained in 

Appendix 9 of the CO2 Emission Performance Rate and Goal Computation TSD for the CPP 

Final Rule to determine the net electric generation and carbon dioxide emissions. In summary, 

the generation is from the EIA-923 form, the emissions for Edgecombe Genco, LLC GEN1 is the 

sum of the Part 75 emissions from Units BLR01A and BLR01B, the emissions for Edgecombe 

Genco, LLC GEN2 is the sum of the Part 75 emissions from Units BLR02A and BLR02B, the 

emissions for the Roanoke Valley Energy Facility I GEN1 are the Part 75 Unit 1 emissions, and 

the emissions for Roanoke Valley Energy Facility II GEN2 are the Part 75 Unit 2 emissions.

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

Commenters stated EPA appears to have incorrectly assigned Electric Generation for all three 

IPP/CHP (Independent Power Producers/Combined Heat and Power) coal-fired plants in North 

Carolina. The commenters said this includes the following plants: Edgecombe Genco LLC, 

Roanoke Valley Energy Facility I, and Roanoke Valley Energy Facility 11. 

Commenters stated EIA-923 reports only Net Generation; EPA appears to have incorrectly 

assigned this value as equal to Electric Generation and recalculated Net Energy Output. The 

commenters believed the correct method for determining Electric Generation would be to take 

the ratio of Electric Fuel consumption over Total Fuel consumption (as reported in EIA-923, 

Schedule 2-5, UtiiPg6_PiantFrame) and multiply this ratio by Net Generation. The commenters

said the difference between Net Generation and Electric Generation equals Useful Thermal 

Output (UTO). The commenters believed EPA's error is propagated further in determining 

"Other'' emissions because it relies on UTO derivation. 

Commenters stated as a result of correcting errors the Sum of Electric Generation and the Sum of 

Net Energy Output should be 50.350,683 MWh and 50.607.838 MWh, respectively. 

Commenters stated EPA has double counted CO2 emissions for CHP plants characterized under 

coal and "Other." The commenters said the total 2012 CO2 emissions for North Carolina's 

Edgecombe Genco Plant is 416,411 tons; EPA determined that 223,731 tons of these emissions 

are associated with thermal output; EPA determined the baseline rate by assigning 416,411 tons 

under coal and 223,731 tons under "Other". The commenters said this results in a total plantwide CO2 emissions of 640,142 which is clearly higher than recorded emissions data. The 

commenters said the correct method for this plant would be to assign 192.680 tons for coal 

(416,411 minus 223,731) and 223,731 tons for "Other'. The commenters said this error correction 

also applies to North Carolina's other two CHP plants: Roanoke Valley Energy Facility I and II; 

it also applies to all CHP plants nationally.

Move from "Existing" to "Under Construction"
258

Commenters stated EPA has incorrectly assigned the Lee EGUs as Existing NGCC; according to 

EIA Form 860 and NCDAQ records, the Lee plant began operations in late December 2012. The 

commenters said EIA Form 923 shows no reported electricity generation and EPA CAMD shows 

no reported air emissions for this plant in 2012. The commenters said although the proposed rule 

has assigned no CO2 emissions levels or electricity generation levels, the EPA has counted this 

plant's capacity as part of North Carolina's "Existing NGCC" The commenters believed that 

1.068 MW NGCC capacity for the Lee plant should be included as "Under Construction" NGCC 

since EPA has not accounted for emissions or generation for this plant in the 2012 baseline 

calculation.

Commenters stated the Dan River EGUs should be moved from "Existing NGCC" to "Under 

Construction" NGCC; the new combined cycle units came on line in late December 2012, and 

operated for less than 10 days; the reported net generation was 135,081 MWh, which equates to 

approximately 2.5% capacity. The commenters said the EPA used the 135,081 MWh generation 

and associated CO2 emissions to calculate unadjusted CO2 for existing NGCC. The 

commenters asserted that the 2012 data for the Dan River plant are unrepresentative of an annual 

operation, and should be excluded from the goal calculation; based on the same reasoning, the 

commenters asserted the plant's NGCC capacity of 691.1 MW should be added to the "Under 

Construction" NGCC capacity.

Commenters stated given the significant emphasis EPA has placed on ramping up existing 

NGCC capacity to 70% and the corresponding displacement in coal generation, the 

commenters pointed out that by including Dan River and Lee in the existing mix of NGCC 

EGUs, both of which generated little to no electricity, North Carolina's existing capacity is 

artificially deflated. The commenters said EPA applied a capacity factor of 37% in the proposed 

rule to determine BSER under Building Block 2.

Peaking Unit

Commenters stated Butler Warner-Fayetteville is owned and operated by the Fayetteville Public 

Works Commission; it originally consisted of 8 peak shaving gas turbines that produced a 

maximum of 200 MW; in 1988, six of these units were converted to a combined-cycle system 

which increased the capacity by 65 MW. The commenters said historically the plant has operated 

as a peak power facility; in addition, Butler-Warner has an agreement with Duke Energy from 

2012 to 2017 to provide electricity during high demand period; in return, the customers of the 

PWC receive lower electricity rates. The commenters said this plant generally operates at an 

annual capacity factor of less than 5%; during peak months January, June, July and August, it 

operates at less than 15% of capacity and during off peak months it operates at less than 2% of 

capacity. The commenters asserted this unit should be considered a peaking unit under the 

proposed rule and excluded from use in Building Block 2 Re-Dispatch of Existing Units; and is 

not capable of increasing its capacity to 70% and operating as a base load unit. 

Commenters stated the Butler-Warner NGCC unit is owned by the Fayetteville Public Works 

Commission ("PWC") and is dispatched by an IOU by contract for the exclusive benefit of PWC. 

The commenters said this unit is not subject to the regulation of the NCUC or oversight by the 

Public Staff. The commenters said including the Butler-Warner facility in existing NGCC 

capacity incorrectly presumes that the unit can be freely dispatched consistent with the Proposed 
259

Rule's 70% capacity threshold. The commenters said the Butler-Warner NGCC unit has operated 

as a peaking facility and operates at a capacity factor of less than 15% during peak months and 

less than 2% during off-peak months. There is no indication that the Butler-Warner NGCC unit 

could be physically dispatched at a 70% capacity factor for a sustained period of time going 

forward. The commenters added the Butler-Warner facility is subject to contractual terms 

between PEC and PWC that control its dispatch through 2017; the NCUC and Public Staff lack 

authority to alter the terms of this contract to force compliance with EPA's NGCC dispatch 

targets. The commenters said no one can obligate the parties to renew the contract after 2017 or 

force PWC to enter into a new contract with other parties. The commenters said based on these 

limitations, the Butler-Warner NGCC unit should be removed from existing NGCC capacity. 

Merchant Plant

Commenters stated Plant Rowan is a merchant plant owned by Southern Power Company and 

contractually dispatched for the benefit of Duke Energy Progress, Western municipalities, and an 

electric membership cooperative authority. The commenters said the Rowan plant is subject to 

separate contractual terms between Southern Company and three other entities with expiration 

dates ranging from December 2015 to December 2015; the plant is not subject to the regulation 

of the North Carolina Utilities Commission (NCUC) or oversight by the Public Staff. The 

commenters said the current long-term contract terms may inhibit running the Rowan units at the 

70% level stated in the Proposed Rule, and the NCUC and Public Staff lack authority to alter the 

terms of the contracts to force compliance with EPA's NGCC dispatch targets. 

Commenters stated the Rowan units and Butler Warner units do not comprise the retail electric 

system in North Carolina, and are not under the authority of the state regulatory agencies; as 

such, the commenters asserted they should not be included in the calculation of existing NGCC 

capacity. The commenters said the inclusion of these plants in the calculation of the goal under 

Building Block 2 assumes that both plants can be part of a new dispatch methodology, when 

there is no mechanism by which a state plan can force either plant to run greater or lesser 

amounts to affect dispatch of the electric unities generation fleet. 

Commenters stated the Rowan NGCC unit is owned by Southern Company and contractually 

dispatched for the benefit of an IOU, municipal power agencies and an electric membership 

cooperative. The commenters said this unit is not subject to the regulation of the NCUC or 

oversight by the Public Staff. The commenters said including the Rowan facility in existing 

NGCC capacity incorrectly presumes that the unit can be freely dispatched consistent with the 

Proposed Rule's 70% capacity threshold. The commenters added the Rowan facility is subject to 

separate contractual terms between Southern Company and three other entities with expiration 

dates ranging from December 2015 to December 2025. The commenters said the NCUC and 

Public Staff lack authority to alter the terms of these contracts to force compliance with EPA's 

NGCC dispatch targets; likewise, no one can obligate the parties to renew the contracts as they 

expire or otherwise force Southern Company to enter into new contracts with new parties. The 

commenters said based on these limitations, the Rowan NGCC unit should be removed from 

existing NGCC capacity. 

Existing NGCC Capacity
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Commenters stated the Rosemary Plant has been operational since 1990; from 2001 through 

2012 (144 months of operation), Rosemary did not exceed a monthly capacity factor of 34%. 

The commenters said the NGCC units are smaller, older vintage types owned by Dominion 

North Carolina Power; the operation is dispatched through the PJM auction process. The 

commenters said due to the age and poor economics, Rosemary units operate at a reduced 

capacity compared with the newer NGCC units. The commenters said the more efficient 

Sherwood H. Smith units and Buck units operate at 30% higher capacity rate and 50-70% lower 

costs than Rosemary. The commenters said due to the operational and economic limitations 

associated with the Rosemary Plant, it is unrealistic to expect attaining a capacity factor of 70% 

as proposed in the rule. The commenters said significant upgrades and major modifications 

would be required to operate Rosemary to 70% capacity factor which would trigger 111(b) and 

PSD/NSR.

Commenters stated the Rosemary NGCC unit possesses unique operational characteristics and 

limitations that render it unsuitable for inclusion in the Building Block 2 calculation. The 

commenters said the Rosemary NGCC unit is a small, older vintage NGCC unit owned by 

DNCP that operates more like a combustion turbine ("CT") unit than a NGCC as evidenced by 

its annual capacity factors for calendar years 2010 through 2013: 2010 - 7.40%; 2011 - 9.36%; 

2012 - 5.51%; and 2013 - 4.66%. The commenters said from January 2001 through December 

2012 (144 months), Rosemary did not exceed a monthly capacity factor of 34%; its operation is 

dispatched through the PJM auction process; thus if it is not dispatched pursuant to PJM's 

auction process then it cannot be dispatched to displace other units within PJM as contemplated 

by Building Block 2. The commenters said as DNCP does not have other generating facilities 

located within its North Carolina service territory, there is no further generation that can be 

offset. The commenters said the fact that it operates so rarely is indicative of its relatively poor 

economics within the PJM footprint, which is illustrated by its 2012 operating data: heat rate of 

9,654 Btu/kWh and Operating and Maintenance ("O&M") Expense of $82.16/MWh (compare 

with the Smith units which had a combined 2012 heat rate of 6,946 Btu/kWh and O&M Expense 

of $37.28/MWh; and the Buck unit which had a 2012 heat rate of 7,087 Btu/kWh and O&M 

Expense of $26.36/MWh). The commenters added the Rosemary NGCC is subject to EPA 

permit restrictions that limit the amount of time that it can run; due to the limitations associated 

with the Rosemary NGCC unit, it is unrealistic to expect it to attain a capacity factor of 70%, and 

it should not be included in the calculation for Building Block 2. The commenters said operating 

the Rosemary unit at a capacity factor in the 65%-75% range would require significant upgrades 

and modifications that would likely trigger EPA's proposed 111(b) rule, notwithstanding the 

other limitations of its currently existing air permit. 

Commenters requested that Lee and Dan River EGUs be moved to "Under Construction" NGCC 

(1,759.1 MW nameplate capacity or 1,541 MW net summer capacity); and North Carolina's 

Existing NGCC nameplate capacity be revised from 4.709.1 MW to 1.930.4 MW (1.722 MW net 

summer capacity) which moves Buck and Smith units to "Under Construction" and Butler 

Warner, Rowan, and Rosemary to "Excluded" NGCC category.

Under Construction Capacity

Commenters reviewed EPA's NEEDS v. 5.13, and found that the 2,249 MW value is based on a 

generic assignment. The commenters said EPA did not identify which specific "planned-
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committed'' units this capacity is based on, and cited data confidentiality restrictions. The 

commenters believed that EPA must disclose the basis upon which 2,249 MW was derived for 

North Carolina. The commenters said EPA also does not provide any justification of how it 

assigned 2,249 MW to North Carolina from a regional (North and South Carolina combined) 

planned capacity estimate of 4,203 MW. 

Commenters stated applying the definition contained in Section 4.3 of NEEDS documentation, 

the commenters believed only three NGCC plants as "Under Construction" because ground has 

been broken, financing obtained, or other demonstrable factors indicate a high probability that 

the unit will be built before 2016; this includes Lee, Dan River, and LV. Sutton: 

• LV. Sutton Combined Cycle Units (730 MW nameplate capacity, 622 net summer 

capacity) 

• Lee Combined Cycle Units (1,068 MW nameplate capacity, 921 net summer 

capacity) 

• Dan River Combined Cycle Units (691.1 MW nameplate capacity, 620 net 

summer capacity). 

• Total Under Construction" NGCC = 2.489.1 MW nameplate capacity. 2.163 net 

summer capacity. 

The commenters said LV. Sutton EGUs (ORIS ID 2713) started operation in January 

2014; EPA's Appendix 7 (Unit-Level-Inventory) in the TSD does not show 730 MW of new 

NGCC capacity for this plant. The commenters said based on this finding, EPA should add 730 

MW to the "Under Construction" NGCC category. 

The commenters said North Carolina's "Under Construction" NGCC nameplate capacity needs to 

be revised from 2.249 MW to 2.489.1 MW or 2.163 MW net summer capacity. The commenters

said if EPA chooses to not move Lee and Dan River to "Under Construction", North Carolina's 

NGCC nameplate capacity should be 730 MW (622 MW net summer capacity) to represent the 

LV. Sutton plant. 

Commenters stated EPA calculates North Carolina's existing natural gas combined cycle 

("NGCC") capacity as of 2012 to be 4,709 MW (nameplate); EPA erred in its baseline 

calculation by including several plants that were under construction in 2012. The commenters

said including the full capacity for H. F. Lee and Dan River in Building Block 2 calculations 

significantly understates the capacity values for NGCCs. The commenters said for H. F. Lee 

NGCC, zero existing NGCC capacity should be attributed to 2012 because zero generation was 

reported for 2012 in EIA Form 923. The commenters said for Dan River NGCC, only 135,081 

MWh of generation was reported for 2012 in EIA Form 923, representing minimal operation as it 

came online at the end of the year; as Dan River NGCC was not operational for more than a 

week or two in 2012, zero existing NGCC capacity should be attributed to 2012. The 

commenters said reclassification of the H. F. Lee NGCC and Dan River NGCC units from 

existing capacity to "under construction" reduces North Carolina's existing NGCC capacity from 

3,869 MW to 2,110 MW. 
262

Commenters stated alternatively, EPA should recalculate its numbers using the pro-rata share of 

H.F. Lee NGCC and Dan River NGCC units that were operational in 2012 to more accurately 

reflect the availability of NGCC generation during the year. The commenters said as there was 

zero electric generation reported for H.F. Lee NGCC in 2012, the calculation yields an effective 

nameplate capacity of 0 MW for H.F. Lee NGCC for 2012. The commenters said applying a 

64.5% capacity factor to the Dan River generation (the average combined capacity factor for 

Smith 4 and 5, Rosemary,13 and Buck NGCC generation for 2012) yields an effective existing 

nameplate capacity of 24 MW for Dan River for 2012. 

Nuclear Capacity

Commenters stated EPA has used an incorrect value for North Carolina's nuclear capacity; both 

EIA Form 860 and Appendix 7 in the 111(d) rule show total nameplate capacity of 5,394.7 MW; 

instead, EPA used 5,016.2 MW in North Carolina's goal calculation in Appendix 7. The 

commenters said the GHG Abatement Measures TSD shows yet a different nuclear capacity for 

North Carolina - 4,970 MW. The commenters said this error needs to be fixed by correcting 

North Carolina's total nuclear nameplate capacity to 5,394.7 MW or 4,998.0 net summer 

capacity.

Comment 245: NC - The EPA should set lower target for NC based on expected growth of RE 

and EE in NC; strengthen target

Response 245: For the EPA’s response to this comment, see sections V.A, V.E, andthe CO2

Emission Performance Rate and Goal Computation TSD for CPP Final Rule supporting the final 

CPP.

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

Commenters stated if EPA had taken into account the actual expected renewable and energy 

efficiency growth in North Carolina, the State's target would be much lower. The commenters

said that North Carolina is poised to achieve a target of 809 lbs/MWh, taking into account the 

expected renewable and energy efficiency growth; EPA should revise North Carolina's target to 

match the real-world reductions that are expected to occur in the state. 

Commenters stated North Carolina is well positioned to not only meet, but surpass the proposed 

goal of 992 pounds of CO2 per net MWh from all affected units by 2030. The commenters said 

the state has great potential for growth in renewable energy generation and energy efficiency, 

and the EPA's assumptions should be strengthened to more closely represent the state's current 

trajectory and opportunities for growth. 

Commenters stated North Carolina has seen tremendous growth in renewable energy generation 

over the last decade; spurred in part by the adoption of the state's Renewable Energy and Energy 

Efficiency Portfolio Standard ("REPS") in 2007 and the state tax credit, solar electric generation 

has grown exponentially. The commenters said in 2013 alone, North Carolina installed 335 MW 

of solar electric capacity, ranking it 3rd in the nation; as of summer 2014, North Carolina ranked 
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4th in the nation in total installed capacity, and in May 2014, ranked 2nd in the country for new 

solar capacity under development. 

Commenters stated it is important to note that a large amount of this development took place 

after 2012, the baseline year used to calculate the emission rate goals; in addition, North 

Carolina's REPS mandate will continue to increase through the year 2021, at which point utilities 

will be required to meet 12.5 percent of electricity demand with renewable energy and energy 

efficiency measures. 

Commenters stated North Carolina also has incredible wind energy potential, and a number of 

wind developers have shown interest in developing large projects in coastal North Carolina. The 

commenters said based on the growth of renewable energy generation that took place after 2012, 

the state's solid and continuing growth in solar development, increasingly affordable solar 

technology and strong wind energy potential, North Carolina's proposed emission rate goal 

should be strengthened to better represent its renewable energy future. 

Commenters stated Building block 4, energy efficiency, also carries strong potential; energy 

efficiency programs can be implemented quickly and at low cost, often resulting in direct savings 

to consumers, businesses and governmental entities. The commenters said while North Carolina 

currently lags behind other states in energy efficiency programs and progress, demand-side 

programs will likely be spurred along with more urgency toward the end of the decade as the 

final REPS goal, 40 percent of which may be achieved through energy efficiency measures, 

approaches. The commenters said there is incredible potential for energy efficiency gains in 

North Carolina, and stronger standards will help to drive innovation and investment in programs, 

technology and incentives; stronger building codes, more comprehensive utility programs and a 

greater focus on multi-family and low-income dwellings will help the state to achieve greater 

demand-side energy efficiency. 

Commenters stated the EPA should strengthen North Carolina's emission rate goal to take into 

account greater potential for energy efficiency measures. 

Commenters stated "The Responsible Energy Future 2015" (www.ncwarn.org/publications) calls 

for North Carolina to achieve the following by 2029: 7% renewable energy, 24% energy 

efficiency, and 10% combined heat and power, as a percentage of total energy sales; phasing out 

all coal-fired power plants; no new natural gas or nuclear plants; and closing the dirtiest natural 

gas and most dangerous nuclear units. The commenters said this transition to cleaner energy will 

benefit North Carolina's economy and health; eliminating coal from North Carolina's energy mix, 

and reducing the use of natural gas keeps the $1.7 billion for out-of-state coal in North Carolina's 

economy, while drastically reducing the climate-harming pollution pumped into the air. The 

commenters said it is clear that a balanced mix of distributed power (putting electricity where it 

is needed) and energy efficiency is the most reliable, cost effective and readily available path 

over the next 15 years. 

Comment 246: NC - BB1 - HRI
264

Response 246: See section V.C. of the final rule preamble of the CPP for the EPA’s response to 

this comment and more information about Building Block 1.

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

Commenters stated North Carolina's 2002 Clean Smokestacks Act resulted in significant 

reductions in nitrogen oxide (NOx) and sulfur dioxide (SO2) emissions from coal-fired 

generation plants; this law also played a key role in decisions to retire older, inefficient coal units 

in order to comply with state law; it also had corresponding carbon emission benefits. The 

commenters said according to the nonpartisan May 2014 report, Benchmarking Air Emissions of 

the 100 Largest Electric Producers in the United States, North Carolina's coal fleet is the most 

efficient in the country with a carbon emission rate of 2,062 lb/MWh. The commenters said 

achieving the NOx and sulfur dioxide SO2 reductions mandated in Clean Smokestacks require 

$7.5 billion in capital improvements; North Carolina ratepayers contributed $2.5 billion of that 

total. The commenters said if the NC efficient coal units are unable to achieve EPA's projected 

heat rate improvement and EPA's interim and final carbon intensity reduction targets reduce the 

useful life of these plants, the ratepayers would be penalized for funding investments that 

significantly cut harmful emissions and led to the retirement of many of the state's older coal 

units. 

Commenters stated EPA's draft rule projects that North Carolina's coal-fired units can operate 

6% more efficiently through heat rate improvements; this target might be achievable for states 

with less efficient coal generation fleet, but it is unclear whether NC's highly efficient coal-fleet 

can achieve comparable heat rate improvements. The commenters said if the projected efficiency 

gains are not technologically or economically feasible, North Carolina would need to find likely 

more costly emission cuts elsewhere. 

Commenters stated if North Carolina's baseline power needs are increasingly met by gas rather 

than coal-fired units, and with coal-fired units operating less efficiently as their utilization rate 

decreases, EPA needs to reexamine whether the projected heat rate improvements are feasible for 

existing coal-fired units in NC and appropriately adjust the required rate reductions. 

Comment 247: NC – Nameplate capacity - BB2

Response 247: The EPA uses summer net capacity values for estimating building block 2 

potential in the final CPP.

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

Commenters stated utilizing nameplate capacity for estimating future generation potential and 

associated CO2 overestimates potential CO2 reductions from adjusted generation profiles. The 

commenters recommended that EPA utilize the "summer net capacity values" rather than 

nameplate capacity to more accurately reflect the generation profile for North Carolina. The 

commenters recognized that CO2 is produced throughout the year, and not just in summer, thus 

further recommends that the EPA utilize a weighted value of seasonal net capacity (summer and 

winter) in calculations involving existing generation. 
265

Comment 248: NC - BB3 RE, the EPA's Building Block 3 is based on an undemonstrated 

regional portfolio approach

Response 248: The EPA has revised its block three quantification based on comments and our 

further consideration. See sections V.A.4.c and V.E. of the final rule preamble of the CPP for a 

discussion of building block three in the final CPP. Section VI of the final rule preamble of the 

CPP explains that the EPA is capturing the replacement effect of renewable on baseline fossil 

generation levels as discussed in the NODA and supported by commenters.

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

EPA should account for actual and expected renewables growth between 2013 and 2017.

Commenters stated EPA should account for actual and expected renewables growth between 

2013 and 2017. The commenters said EPA starts with each state's 2012 renewable energy 

generation, and then assumes that states will not begin ramping up renewable energy from 2012 

levels until 2017. The commenters said this approach fails to capture any of the recent or 

expected growth in renewable energy in North Carolina between 2012 and 2017, ignoring the 

significant investments that are already underway. The commenters said since 2012, North 

Carolina's renewable energy generation has increased from 2,704 GWh to 3,224 GWh; these 

increases are expected to continue due to North Carolina's ongoing RPS obligations and the 

ongoing dramatic cost declines in solar and wind technologies. The commenters said this growth 

in renewable generation to date reduces North Carolina's emission rate by 56 lbs/MWh. The 

commenters said EPA should strengthen the renewable assumptions underlying its target for 

North Carolina to take into account the significant increase in renewable energy since 2012. The 

commenters added, EPA should update these numbers again prior to 2017 to ensure that 

renewable energy targets reflect the real world investments that have already been made, 

allowing state targets to become more aggressive as states ramp up their renewable generation. 

EPA should assume full compliance with current RPS requirements that are set by state law.

Commenters stated North Carolina's REPS requires that the state's electric power suppliers 

(investor-owned utilities, electric membership corporations or co-operatives, and municipal 

utilities) supply an increasing portion of their retail electricity sales from renewable energy or 

energy efficiency resources. The commenters said beginning in 2012, each electric power 

supplier was required to meet 3% of the prior year's retail electricity sales from renewable energy 

resources; this percentage ultimately increases to 10% of retail sales in 2018 for all suppliers 

(capping out at this level for EMCs and municipal utilities), and 12.5% in 2021 for the investorowned utilities. The commenters said through 2020, up to 25% of the total requirement (3.125% 

of sales) can come from implementation of energy efficiency and demand-side management 

measures, and in 2021 and after up to 40% of the requirement (5% of sales) can come from 

EE/DSM. The commenters said under the REPS, renewable energy generated out of state may be 

purchased and used for compliance as long as it is delivered to a public utility that serves retail 

electric customers in North Carolina; in addition, utilities may comply by purchasing renewable 
266

energy certificates ("RECs"); no more than 25% of the requirements may be met with out-ofstate RECs, however. N.C. Gen. Stat. section 62-133.8(b)-(c). 

Commenters stated under EPA's proposed approach, 17 of the 29 states with RPS obligations 

under state law have lower targets under the EPA approach than what is required to meet their 

existing state laws; this includes North Carolina, whose electric suppliers have an obligation 

under its REPS to achieve approximately 34 million MWh of clean energy by 202117, but 

only11.7 million MWh by 2030 under EPA's proposed rule. The commenters said this cannot 

reflect the "best" system of emission reduction; EPA should assume that state will achieve the 

greater of their EPA regional target or the level of renewables needed to comply with their state 

RPS obligations, and adjust the targets for states like North Carolina accordingly. 

EPA should ensure that the rate of renewables deployment is at least as aggressive as historical 

rates. 

Commenters urged EPA to ensure that the rate of renewable energy deployment assumed in the 

CPP's analysis is at least as aggressive as the historical rates of deployment. The commenters

said this will ensure that renewable energy targets truly reflect the "best" system of emission 

reduction, based on real world information. The commenters said EPA can use this information 

to set a national renewable energy growth rate benchmark based on demonstrated growth 

nationally from 2009 to 2013. The commenters said the Union of Concerned Scientists ("UCS") 

has developed a "Demonstrated Growth" approach, which calculates a national average 

renewable energy benchmark growth rate of 1% of annual electricity sales based on actual state 

data from 2009 to 2013 from EIA. The commenters encouraged EPA to adopt the UCS 

Demonstrated Growth approach; for states below the benchmark, EPA should assume that these 

states can gradually achieve 1% by 2020 and continue at that level through 2030, similar to the 

approach that EPA takes for the energy efficiency building block. The commenters said for the 

leading 15 states, EPA should assume that they can continue at their five-year average rate up to 

1.5% per year; this approach will better reflect recent growth in renewable energy across the 

country and allow those states with the best renewable energy policies to be captured in the rule 

rather than diminishing these aggressive state goals through averaging. 

The commenters said if EPA adopts these recommendations - increasing renewable energy 

growth rate benchmarks to reflect national best practices, assuming full compliance with state 

RPS policies and accounting for renewable energy growth from 2013-2017 - UCS projects that 

these tweaks would increase the state's renewable energy target in 2020 from EPA's proposal of 

4,477 GWh to 11,621 GWh. The commenters said in 2030, North Carolina could achieve 26,674 

GWh of renewables, compared to EPA's proposed target of 11,668 GWh; this analysis confirms 

that much more ambitious renewable energy targets are achievable. 

EPA should update its formula to account correctly for emission reductions from renewable 

energy. 

Commenters stated in its October 27, 2014, Notice of Data Availability ("NODA"), EPA 

explains that the formula used in its proposed rule did not adequately account for the emission 

reductions from renewable energy; as EPA explains, the original formula failed to account for 

the reduction in generation at coal and gas power plants that will occur when generation from 
267

additional renewables is added to the grid. The commenters said when EPA sets final state 

targets, it should use the corrected formula proposed in the Notice of Data Availability to ensure 

that renewable energy is given full credit for its ability to displace fossil generation and reduce 

emissions from carbon dioxide. 

Other

Commenters stated the 2007 North Carolina Renewable Energy and Efficiency Portfolio 

Standard (NC REPS) law requires investor-owned utilities to annually generate 12.5% of 

electricity from renewable sources by 2021. The commenters said the law allows energy 

efficiency to account for up to 25% of the mandate through 2020 and 40% after 2021. The 

commenters said North Carolina remains the only state in the Southeast with a mandatory 

renewable electricity law. The commenters are concerned that EPA's methodology for setting 

state renewable targets could result in higher compliance costs for North Carolina. 

The commenters said in 2012 renewables represented 0.4% of Kentucky's total electricity 

production; EPA projects that amount can grow to 2% by 2030; during that same period, North 

Carolina's percentage of electricity from renewables is projected to grow from 2% to 10%. The 

commenters said while this represents a five-fold increase in renewable generation for both 

states, the incremental costs achieving a 1.6% increase would presumably be much less than 

attaining an 8% increase. 

The commenters said EPA should adjust North Carolina's carbon reduction targets to reward 

NC for enacting mandatory renewable power standard that reduced carbon emissions. The 

commenters said North Carolina demonstrated that a southeastern state could embrace 

renewables in a cost-effective manner and should not be burdened with higher compliance costs 

because elected officials in other states did not to take similar actions. 

Commenters stated in Table 4-2 of the TSD, EPA concluded that North Carolina's 2020 

"Effective RE Rate" is 10%, which is used to establish final RE generation targets for North 

Carolina and other Southeast states; however, North Carolina's REPS law and North Carolina 

Utility Commission (NCUC) orders allow that 10% RE to be met through several other means 

besides in-state RE including the following: 

• Energy efficiency / demand side management 

• Out of state generation 

• Small hydroelectric generation 

• Out of state purchases / Renewable Energy Certificates (REC) 

• Thermal purchases 

Commenters said because of these provisions, North Carolina is not expected to implement instate RE at a level of 10% of electricity sales; therefore, using North Carolina's REPS law to 

establish 10% RE as BSER for the Southeast is incorrect. The commenters said EPA should have 
268

subtracted out the expected implementation rate of these other provisions from the 10% 

"Effective RE Rate" prior to establishing BSER. 

Commenters said under the rule, EE can account for up to 40% of the RE target in 2021; as 

stated in the proposed rule and experienced in North Carolina, EE actions are considered lower 

cost options; therefore, the commenters asserted that the entire allowable EE percentage will be 

implemented by the utilities, and should be separated from RE rate calculation. 

Commenters said based on the NCUC's evaluation, the actual 2020 "Effective RE Rate" should 

be 3.14% of retail sales for Investor Owned Utilities and 5.53% of retail sales for municipalities 

and cooperatives; the weighted average REPS for all suppliers (total in state renewable portion) 

is 3.75% of 2020 sales. The commenters said by 2021, the RE rate drops to 3.07% of sales 

because state law allows higher portion of the REPS supplied through energy efficiency 

measures. 

Commenters said since EPA is using a single RE rate to establish future RE generation targets, 

the commenters are requesting EPA to change the 10% "Effective RE Rate" in the rule to that 

based on each state's technical and economic potential; in North Carolina's case, the state's REPS 

represents the product of such analysis and the appropriate targets/provisions contained in the 

REPS be used as BSER for North Carolina. 

EPA has misinterpreted Renewable Energy (RE) requirements under the NC REPS. 

Commenters stated the NC REPS specifies RE requirements in terms of total sales, not in-state 

electricity generation; since North Carolina imports electricity, actual generation is less than the 

annual sales amount. The commenters said in the proposed rule, EPA started with 2012 RE 

generation for each state, and defined a "Region Target'' level of RE performance in 2020 based 

on the average of each state's REPS. The commenters said for North Carolina and other states in 

the Southeast Region, EPA used a 2020 Effective RE rate of 10% based North Carolina's REPS 

to represent the "Region Target;" EPA then calculated each region's RE goal by multiplying the 

total region-wide 2012 generation with the "Region Target" (i.e., 10%). The commenters said for 

North Carolina, EPA multiplied the 2012 RE in-state generation (116,681,763 MWh) with 10% 

to arrive at 11,668,176 MWh state goal. The commenters said the true "Region Target'' using 

EPA's approach should be based on each state's own technical and cost analysis of RE potential; 

for North Carolina, the REPS represents the results of such analysis and its associated 2020 

target of 3.75% of sales and 2021 target of 3.07% of sales should be used by EPA North 

Carolina's REPS is based on a percent of sales, EPA must revise its calculation by correcting for 

instate generation as a function of annual sales. The commenters said in 2012, North Carolina's 

in-state electricity generation was 86.12% of total sales, which means 13.88% was 

imported; EPA can do one of the following to most accurately represent North Carolina's REPS 

into its goal calculation: 

1. Divide the 2012 in-state generation by 86.12% or 

2. Divide the 3.07% of sales RE "Region Target'' by 86.12% 

The commenters said applying the above method results in North Carolina's RE goal of 

4,159.464 MWh instead of 11,668,176 MWh used in the proposed rule. 
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Recalculate Annual Growth Factor for the Region

Commenters stated errors from misinterpreting the RE requirements under the NC 

REPS propagates to the "Annual Regional Growth Factor'' calculation. The commenters said 

when the 3.07% of sales RE "Region Target" is applied and in-state generation is replaced with 

total sales, the corrected "Annual Regional Growth Factor'' is 4.8% instead of 13.4% used in the 

rule.

Biomass

Commenters stated removing biomass from the 2012 RE generation that EPA used in the rule for 

North Carolina, results in 139.491 MWh of RE as a starting point. The commenters said this 

significantly changes the proposed interim and final RE targets.

Commenters stated, EPA bases its renewable energy ("RE") target for every state in the 

Southeast exclusively on one legislatively adopted, undemonstrated RPS - the North Carolina 

Renewable Energy and Energy Efficiency Portfolio Standard ("REPS"). Commenters said, EPA's 

approach would thus impose one state's legislative choice onto numerous surrounding states, 

ignoring North Carolina's policy priorities and other state-specific factors that led to enactment 

of that state's standards. Commenters said, moreover, EPA conveniently omits significant aspects 

of North Carolina's REPS that make EPA's version of the standard much more stringent than the 

version actually adopted.

Commenters stated, unlike EPA's version, the North Carolina REPS is not simply a mandate for 

utilities to generate a certain percentage of their electricity from renewable resources by a certain 

date. Commenters said, to the contrary, it is a combined program for RE and energy efficiency in 

which regulated parties can use a combination of renewable generation, efficiency projects or 

demand reduction to meet a single standard. Commenters said, because EPA's proposal fails to 

recognize this fact, Building Block 3 is without precedent anywhere in the southeastern United 

States and fails to satisfy the requirements of BSER.

Commenters stated, pursuant to N.C.G.S. Section 62-133.8(b)(1), public utilities are subject to 

an RPS requirement that increases from three percent "of retail sales" in 2012 to 12.5 percent "of 

retail sales" in 2021. Commenters said, section 62-133.8(b)(2) then provides that utilities can 

meet this requirement through a variety of means. Commenters said, importantly, public utilities 

may use reduced energy consumption from the implementation of energy efficiency measures to 

satisfy between 25 percent and 40 percent of their requirement, and they can use electricity 

demand reduction to meet 100 percent of their requirement. Commenters said, in other words, 

EPA's assumed levels of renewable generation for southeastern states are based on a standard 

that allows utilities to comply without any reliance on renewable energy whatsoever. 

Commenters said, given that utilities can use energy efficiency-oriented actions to comply with 

the North Carolina REPS fully, the North Carolina REPS cannot be viewed as a judgment by the 

state of North Carolina as to its ability to generate electricity from renewable resources 

practically nor should it be used to make judgments about any other state's ability to do so.

Commenters stated, what is more, the statute itself confesses the RPS may be unrealistic. 

Commenters said, it authorizes the North Carolina Utilities Commission ("NCUC") to delay or 
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modify - in whole or in part - all of the substantive requirements of the North Carolina REPS 

upon a showing that it is in the public interest to do so. [See N.C.G.S. section 62-133.8(i)(2).] 

Commenters said, utilities need only demonstrate that they have made a reasonable effort to 

comply. Commenters said, in contrast, any RPS that is included in a state's section 111(d) plan 

could not be changed without prior approval of EPA, and then only if the state shows that such a 

change is necessary in order to meet the emissions goal. Commenters said, moreover, North 

Carolina requires utilities to either shift generation to renewable resources or to achieve 

equivalent reductions in non-renewable generation through energy efficiency and demand 

reduction, but it allows utilities to use both mechanisms to meet the overall 12.5 percent RPS 

target. Commenters said, as a result, the proposal treats the North Carolina REPS as far more 

than what it really is.

Commenters stated, nonetheless, EPA assumes southeastern states can obtain 10 percent of their 

generation from renewable energy and meet separate, aggressive energy efficiency levels. 

Commenters said, in addition, North Carolina has left itself the equivalent of an "escape hatch" 

from its more modest requirements - in order to protect the public interest - due to the potential 

difficulties that could arise during implementation. Commenters said, EPA's proposal has no 

such escape hatch. Commenters said, because no state in the Southeast region has come close to 

demonstrating the level of renewable generation EPA assumes, EPA has failed to establish that 

its estimates of renewable generation in the Southeast have been Adequately Demonstrated.

Comment 249: NC - BB4 EE

Response 249: See section V.A. of the final rule preamble of the CPP for the EPA’s response to 

this comment and more information about Building Block 4.

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

Commenters stated EPA has made an error in the assumption that EE savings can keep growing 

at the same rate (1.5% of retail sales) for years into the future. The commenters said the type of 

EE measures that have been implemented to date and those that are likely to be pursued in the 

future will be different. The commenters said beyond energy efficiency lighting measures and 

other "low hanging fruits" which North Carolina has implemented in the recent past, future EE 

savings will need to come from costly equipment upgrades and replacements and consumer 

behavior modification programs. The commenters said the cost and outcome of such measures is 

unknown and should not be assumed to be easily implementable or achievable. The commenters

said because of the calculation errors and incorrect assumptions underlying the EE savings goal 

of the Proposed Rule, EPA should withdraw the 1.5% annual incremental savings goal, and the 

10.3% annual cumulative goal for 2029, and work with the State to develop goals that are 

technically and economically feasible for North Carolina based on North Carolina-specific facts. 

Comment 250: NC - Proposed rule relies on NC RPS, but it contains no provision for 

determining which state takes credit across state lines
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Response 250: See section VIII.L. 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:

According to commenters, the North Carolina RPS standard allows for out of state power 

purchases to account for up to 25% of the renewable standard. Commenters indicated, however, 

that in the North Carolina RPS there is no provision for determining who can take credit across 

state lines in the RPS, negating the type of negotiation required by the proposed rules. 

Comment 251: NC - Calculated gross heat rate for NC and all states for 2012, NC has lowest 

state-wide average heat rate in country, Clean Smokestacks Act changed fleet and lowered CO2 

emissions significantly

Response 251: See section V.C. of the final rule preamble of the CPP for the EPA’s response to 

this comment and more information about Building Block 1.

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

Commenters indicated that since the EPA did not provide the data for individual EGUs analyzed 

in its statistical approach, they were unable to discern where North Carolina's fleet ranked 

relative to others. Commenters said to assess the relative performance of their coal fleet, they 

calculated the state-level gross heat rate using EPA AMPD data for year 2012. Commenters said 

they found that North Carolina's 2012 gross heat rate for coal-fired EGUs was 9,071 Btu/kWh, 

which is significantly lower than EPA's national average of 9,753 Btu/kWh and the lowest in the 

country. Commenters said North Carolina's heat rate performance results are before making 

corrections that EPA made to account for variability in meteorology and capacity factors, and 

would most likely be lower when these factors are accounted for.

Commenters said having the lowest gross heat rate reflects that some or most of North Carolina's 

coal-fired EGUs have successfully implemented efficiency measures prior to the proposed 

rulemaking. Commenters said North Carolina's heat rate values can be correlated with the 

actions taken by the state legislature with the enactment of the Clean Smokestacks Act in 2002 

which required significant reductions in NOx and SO2 emissions from coal-fired EGUs. 

Commenters said that compliance with the law resulted in multiple retirements, natural gas 

conversions, and add-on pollution control equipment, with 2013 being the final compliance year 

for meeting emissions targets. 

Commenters said the 2012 heat rate data presented here reflect the operating changes that 

occurred at the EGUs as each of the affected plants were retrofitted with NOx, SO2, and PM 

controls. Commenters said it should be noted that in 2012, a significant shift to natural gas had 

already occurred, and many coal-fired EGUs were operating at much lower capacity than 

previous years, yet despite this change, North Carolina's state-wide average heat rate remained 

the lowest in the nation. Commenters indicated the cumulative effect of the EGU fleet change 

was to reduce CO2 emissions. Commenters said that North Carolina's CO2 rate declined during 
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the recession and increased post-recession, and the CO2 rate was at the lowest level in 2012 due 

to compliance with the CSA and a shift to lower carbon emitting fuels.

Comment 252: NC - The EPA should provide state-specific cost/benefit projections

Response 252: For the EPA’s response to this comment, see the Regulatory Impact Analysis for 

the Clean Power Plan Final Rule, EPA-452/R-15-003 supporting the final CPP.

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

Commenters stated with EPA offering state-specific emission reduction projections for 

regulators to consider when developing Implementation Plans, EPA should also provide statespecific cost/benefit projections; the commenters asked: 

a) What impact would the carbon intensity reductions that EPA projects North Carolina 

can achieve under "Option 1" have on retail electricity prices for the state's residential, 

commercial, and industrial users in 2020, 2025, and 2030.

b) What are the net economic benefits that EPA projects North Carolina will receive from 

the proposed rule.

Comment 253: ND - general goals

Response 253: For the EPA’s response to this comment, see sections VI and VII of the final rule 

preamble and CO2 Emission Performance Rate and Goal Computation TSD for CPP Final Rule 

supporting the final CPP.

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

Commenters stated the technical basis for the calculation of the North Dakota CO2 emission 

requirements in that proposal contains numerous serious errors. The commenters believed that 

the Proposed Rule is flawed, and should not be finalized.

Commenters remarked primarily about ND's IRP process. Commenters continued (verbatim) 

“North Dakota's IRP process results in long-range plans that seek the optimal combination of 

resources to meet forecasted load requirements at the lowest reasonable cost. The Proposed Rule 

ignores the existing rigor of the North Dakota IRP process and the state level decisions and 

orders that govern it, in an attempt to decree a new standard to which North Dakota would have 

to comply. Once utility assets are placed in service that investment is ratably charged back to 

customers so long as the asset remains "used and useful" in the provision of utility service. Over 

time, assets may become less efficient, not have the same capabilities as other assets of more 

recent design, or have operating expenses that differ from the estimates made when the asset was 

new. But those circumstances do not prompt the premature retirement of those assets. Instead, 

state Commissions closely evaluate and monitor resource types, capacity, fuel usage and cost, 
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condition of the resources, anticipated retirements, and have investigated the prudence of 

additional capital investments to improve unit efficiency and lower emissions for years in 

advance, all for the benefit of customers. Various scenarios and sensitivity analyses are 

conducted, major assumptions are reviewed, and revenue requirements are evaluated to 

determine the incremental impacts of changed circumstances. The Commission engages in an 

ongoing and iterative regulatory process that allows for careful planning and review, and timely 

reaction to the dynamic changes in load characteristics and resource mix. Capacity additions are 

made under these process guidelines and are traditionally secured from the asset type that 

provides the most benefit to customers at the least cost, while satisfying the need for adequate 

and reliable service. Uneconomic choices are discarded in favor of the more economic and 

reasonable options. State IRPs, and specifically the North Dakota IRP process, is established to 

allow the utility, customers, other stakeholders and the Commission to review the planning 

assumptions, projected fuel costs, and resource options with sufficient frequency to adjust to 

changes in technology, fuel prices, economic conditions, and other factors in a reasoned way. 

Orders and directives of the Commission, including this inclusive stakeholder process, would be 

discarded by the Proposed Rule, in favor of a system of arbitrary goals built on inaccurate 

information and disregard for the proper functioning of the electricity system, all to the detriment 

of North Dakota, the Commission, utility customers and other stakeholders.”

Comment 254: ND - projected electrical load growth in ND due to development of Bakken oil 

reserves, existing lignite-fueled based EGUs would be forced to retire early though they could 

meet demand 

Response 254: See section VIII.G. 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 the Williston Basin Oil and Gas Related Electrical Load Growth Forecast 

Study forecasts an expected electrical load growth for the next 20 years, from 2012 to 2032, in 

the study area which spans regions across North Dakota, South Dakota and Montana. The 

commenters said numbers and figures were calculated from a demand amount averaged between 

historically observed energy use values and maximum oilfield electrical load requirements, and 

represent the study's most likely (consensus) scenario. The commenters said energy use for prior 

years was provided by the Partners and used to establish a 2011 baseline. The commenters said 

by the end of the study period in 2032, the 43 counties within the Williston Basin are projected 

to require 2,512 megawatts (MW) of additional electrical demand, related to oil and gas 

development, to accommodate population growth, new ancillary business development and more 

than 30,000 additional wells. 

Commenters stated the results of the extensive Study will be used by the State of North Dakota 

and certain utilities to effectively plan for critical infrastructure needs and development in North 

Dakota, South Dakota and Montana. The commenters said the study and report includes analysis 

of petroleum-sector commercial and industrial development, employment, population growth 

and secondary employment. The commenters said the Commission shares EPA's concern that 
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"state plans for emission reductions...must be consistent with a vibrant and growing economy 

and supply of reliable, affordable electricity to support that economy." The commenters

said efficient existing lignite-fueled baseload electric generation facilities should not be 

prohibited by the Proposed Rule from being available for meeting the substantial electrical 

demands in North Dakota. The commenters said the Proposed Rule directly threatens the ability 

of existing lignite generation to address these demands. 

Comment 255: OH - Regulation would have disparate impacts among the states

Response 255: See section I.A. of the final rule preamble of the CPP for the EPA’s response to 

this comment. Also see section V of the final rule preamble for a discussion of the building 

blocks and final BSER determination. See section VIII of the final rule preamble for a discussion 

of state plans. 

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

Commenters stated that the Existing Source Proposal is unreasonable and unlawful because it 

would have disparate impacts among the states. Commenters said that Ohio, for example, which 

has been identified as the state most impacted by the proposal in the Midcontinent Independent 

System Operator region, would have to reduce its CO2 emission rate by 25 percent in 2030 

(relative to EPA's base case assumptions). Commenters indicated that this is a considerably 

greater rate reduction than what most other states would be required to achieve. Commenters

said further, Ohio would have to increase its renewable energy generation by 10 percent and its 

energy efficiency savings by 8 percent (relative to 2012 levels), which far surpasses the increases 

that would be required for a majority of states. 

Commenters said that Ohio would take the brunt of the Existing Source Proposal, due, at least in 

part, to the fact that Ohio has a significant amount of coal-fired generation, and also has some 

available NGCC capacity. Commenters said that unlike states with little or no coal-fired 

generation, or states with a significant amount of coal-fired generation but no or little available 

NGCC capacity, the EPA assumed that Ohio can make significant reductions under building 

block 2 (i.e., redispatch to NGCC).

Commenters stated, U.S. EPA identifies what they call "state-specific goals... based on 

consistent application of a single goal-setting methodology across all states, the goals account for 

these key differences...because EPA used data specific to each state's EGUs and certain other 

attributes of its electricity system (e.g., current mix of generation resources)." [79 FR 34836] 

U.S. Commenters said, EPA further states they are using a output-weighted-average emission 

rates for all affected EGUs in a state rather than nationally uniform emission rates for all affected 

EGUs of a particular type which is consistent with the varying types of EGU's and varying 

magnitude of shifting that can occur among individual states, thereby giving consideration to 

CAA Section 111(d) which "calls for standards of performance to be established in state plans 

rather than on a nationwide basis." [79 FR 34894] Commenters disagreed and believe U.S. EPA 

is searching for a justification for this proposal. Commenters said, U.S. EPA's use of the four 
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building blocks to effectively reduce Ohio's state goal does not take into account state specifics 

at all as discussed in their comments.

Commenters stated, this is undoubtedly a national plan and a forcing of a regional approach. 

Commenters said, U.S. EPA has clearly set BSER in every building block based on some method 

of averaging whether at a regional or national level. Commenters said, in no way is U.S. EPA 

proposing a goal or standard that is state-specific or allows for the states to apply the standard in 

a state plan based on what has been and can be achieved in the state itself. Commenters said, 

justifying this averaging for all affected EGUs rather than a national uniform rate is in 

consideration of Section 111(d)'s requirement for standards of performance to be on a state rather 

than national basis is actually counterintuitive to what actually is intended. Commenters said, 

states are charged with developing a standard of performance, taking into account remaining 

useful life, for their individual units based on U.S. EPA's determination of a cost-effective and 

technically feasible BSER for those unit types. Commenters said, states have the ability to a 

make adjustments based on remaining useful life and apply a standard of performance to each 

unit rather than an average across units. Commenters said, U.S. EPA has failed to give 

consideration to this very specific element of the CAA.

Commenters stated that Ohio supports maintaining the flexibility to develop its own standard of 

performance for individual EGUs based on state specific information, cost and technical 

feasibility because EPA relies on "non-BSER" options for "state flexibility," but these are flawed 

and will not be feasible.

Commenters stated that in the NODA, the EPA acknowledges concerns that, with respect to 

states with large amounts of coal-fired generation, the proposed approach to building block 2 

creates significant disparities in state goals between those states with little or no available NGCC 

generating capacity, and those with significant amounts of available NGCC capacity. (79 Fed. 

Reg. at 64549). Commenters said that the EPA then goes on to suggest that this problem could 

be alleviated by requiring states with little or no available NGCC capacity to build new NGCC 

plants and/or for existing coal-fired plants to co-fire with natural gas. (79 Fed. Reg. at 64550). 

Commenters stated that aside from the fact that co-firing with natural gas may be prohibitively 

expensive for some coal-fired units and potentially raises New Source Review concerns, the fact 

that the EPA believes it has the authority to require states to build new NGCC plants 

demonstrates just how far afield of its lawful authority the agency has gone with the Existing 

Source Proposal.

Comment 256: OH has robust EE and RE sectors in place, on plan to reduce CO2

Response 256: The EPA recognizes the current EE and RE sectors in place in OH to reduce 

CO2 emissions.

The following are summaries of the specific public comments under this comment:
276

Commenters stated in cutting carbon emissions from power plants, Ohio is already of the game 

with robust energy efficiency and renewable energy sector in place. The commenters said Ohio's 

efficiency and renewable's law is on hold for two years, but the law, once fully implemented, can 

be an important part of the calculus as the state devises a compliance plan. The commenters said 

these energy efficiency investments can reduce carbon emissions by a conservative 32 million 

tons in Ohio, the amount emitted by 6.7 million cars.

Comment 257: OH - goal assumption errors: mathematical flaws; inappropriate reliance on IMP 

and EIA; Affected Units

Response 257: As explained in section V.D of the final rule preamble of the CPP, the EPA is 

relying on net summer capacity to assess building block two potential in this final rule. In 

regards to the Dresden facility, the EPA emission performance rate and state goal calculation 

recognize that it began operation in 2012, and thus the data may not be representative. 

Therefore, the final rule treats the facility as under construction and assumes a 55% capacity 

factor for the unit which increases the assumed baseline generation level to be more consistent 

with the commenters suggested level. The EPA has removed Orville and Hamilton from the 

baseline inventory of likely affected units per the comment and a review of the nameplate 

capacity. 

Please see the Regulatory Impact Analysis for the Clean Power Plan Final Rule, EPA-452/R-15-

003 and IPM documentation for a discussion of IPM assumptions.

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

Mathematical Flaws

Commenters stated in calculating the state of Ohio's goal emission rate, the CPP relies on faulty 

assumptions instead of using the best available information; in Appendices 1 and 2, the CPP does 

not use correct generation figures for Ohio; to illustrate, consider the following: 

• The Dresden Plant's net generation for 2012 was 2,599,011 megawatt hours 

(MWh), whereas US EPA's eGRID data calculated it as 470,486 MWh. 

• The "Under Construction NGCC Capacity (MW)" for Ohio is stated at 539 

megawatts (MW) for the Dresden Plant; however, the Dresden Plant has been 

built and is already accounted for by US EPA in the existing NGCC calculations. 

• US EPA calculates existing Ohio nuclear capacity at 2,150 MW using United 

States Energy Information Administration (US EIA) data; US EIA Form 860 

states that Ohio's existing nameplate capacity is 2,282.5 MW. 

The commenters said the CPP assumes that all generation units can run on nameplate capability; 

both summer and winter capabilities are significantly less than nameplate capability. The 

commenters said in Ohio, the summer capability for NGCC plants is 447.2 MW less than the 
277

nameplate capability; this error most impacts building block 2, which relies extensively on 

generation dispatch capabilities. 

Inappropriate Reliance on IPM and EIA 

Commenters stated U.S. EPA relied on results generated by IPM in the development of the 

proposal and the assessment of the economic, reliability, and technical feasibility. The 

commenters have concerns with this approach, based on a number of assumptions and results 

that do not seem technically sound, feasible, or reasonable. The commenters conducted an 

analysis of the limited parsed IPM results made available on the docket as well as those IPM 

scenarios for which parsed files were not made available, analyzing specifically Option 1, Statespecific compliance policy case, the Regional Plan scenario, State Plan Blocks 1 and 2 only, and 

the base case scenario. The commenters' primary concern is that a decrease of between 4 and 7 

million tons of CO2 (dependent upon which scenario is in question) was predicted between the 

base and policy cases in 2025. The commenters said overall, IPM projects a ~26% decrease in 

CO2 tonnage from 2005 levels in Ohio; this will be extremely challenging and practically 

impossible for several reasons. The commenters said as a deregulated state, implementation of 

the proposal would likely involve an extensive reconstruction of the power grid and electric 

distribution both within Ohio and across the entire PJM reliability region. The 

commenters understood that the creation of a plan in accordance with the proposal would be an 

intensive, complex, and costly process for many states. The commenters found it difficult to 

reconcile the considerable expenditure of resources and effort that would be necessary under the 

proposal to realize a net benefit of 4 to 7 million tons of CO2, relative to the base case scenario 

by 2025, especially because OH expect to already achieve significant reductions absent this 

proposal. 

Affected Units

Commenters stated USEPA's Carbon Guidelines, specifically the inclusion of the City of 

Hamilton, Ohio and the City of Orrville, Ohio's small fossil fuel-fired units in USEPA's baseline 

calculations, will likely lead to unwarranted and unreasonable increases in electricity rates if 

those units continue to be included in USEPA's calculation of Ohio's baseline and carbon goal 

computation. The commenters said the Carbon Guidelines directly impact Hamilton and Orrville 

because USEPA has incorrectly identified the fossil fuel-fired units at the Hamilton Municipal 

Power Plant and the Orrville Utilities Power Plant as affected sources subject to the Carbon 

Guidelines; as such, US EPA included these units in the agency's determination of Ohio's carbon

baseline and goal computation. 

Clarification

Commenters stated in reviewing the example for Ohio from the TSD, it appears that the 

historical, unadjusted emission rate does not include in its denominator any megawatt 

contribution from renewables or nuclear. When the commenters went to the EPA state maps, the 

pulldown notes suggest that the megawatt includes non-fossil sources; can EPA please clear this 

inconsistency up; does the historical, unadjusted, fossil emission rate have any contribution from 

non-fossil sources in its denominator.
278

Comment 258: OH RE targets are inconsistent with OH law; regulation reflects bias against 

states with RPS standards, hydropower generation excluded in determining annual growth for 

OH, etc.

Response 258: See section V.E. of the final rule preamble of the CPP for the EPA’s response to 

this comment and more information about Building Block 3.

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

Commenters stated the CPP's attempt to apply a blanket, national approach to renewable energy 

(RE) ignores the intricacies of Ohio's laws and policy. The commenters said assuming the CPP 

survives likely legal challenges, the proposed RE targets fail to utilize state-specific approaches 

in determining their respective building block requirements. The commenters said individual 

state renewable portfolio standards (RPS) and energy efficiency programs reflect state-specific 

energy policy objectives, existing generation portfolios, varying degrees of electric market 

restructuring, participation in RTOs and other diverse characteristics embodied in state 

legislation and policy. The commenters said the CPP, while preaching flexibility, does not fully 

take these individual state approaches into account in developing building block 3; the following 

issues exist. 

a. The CPP's Ohio RE targets are inconsistent with state law in Ohio. 

The commenters said the RE targets utilized in the CPP do not reflect current law in Ohio; US 

EPA should utilize 6.5 percent as the 2020 effective RE level for Ohio in deriving Ohio's RE 

targets, rather than the number included in the original calculation. The commenters said as state 

legislatures control the adoption and amendment of RPS policies, US EPA must account for this 

by allowing states to amend their implementation plans and adjust goal emission rates 

accordingly, assuming RPS mandates are included in state plans. 

b. The CPP's NERC-based regions reflect a bias against states with RPS standards. 

The commenters said the CPP creates a RE generation target for Ohio based upon the average of 

all 2020 RPS requirements in the NERC-based East Central region. The commenters said states 

without RPS mandates in this region, however, are excluded from this calculation. The 

commenters said this exclusion manufactures more aggressive RE targets for the RPS states 

within the region, ignoring the reality across the country that renewables have not yet penetrated 

all state market-places. The commenters said the CPP can correct this by utilizing state-specific 

RPS requirements (or lack thereof) in considering RE benchmarks, as opposed to using this 

regional approach. 

c. The CPP wrongfully excludes hydropower generation in determining the annual growth 

formula for Ohio. 

The commenters said the CPP incorrectly excludes hydropower generation from the calculations 

used to determine Ohio's growth factor rate (as discussed in a subsequent section). The 

commenters said although the CPP correctly notes that hydropower generating capacity has been 
279

relatively flat over the last 20 years, this broad generalization does not take into account Ohio's 

distinctive characteristics. The commenters said it is true that only a handful of states have large, 

existing hydroelectric facilities; however, over the past 15 years, significant hydropower projects 

have been developed and are continuing to be developed along the Ohio River within the PJM 

footprint in the East Central region. The commenters said the CPP should recognize these 

investments in hydropower capacity in Ohio and the region. The commenters said the CPP 

should include Ohio's 2012 hydropower generation in the 2012 historical baseline RE data and 

utilize hydropower generation in determining the annual growth factor used for calculating 

Ohio's RE generation targets. 

d. Ohio's growth factor rate is incorrect. 

The commenters said the proposed RE targets in the CPP should be modified to reflect a statespecific approach that is consistent with state law and adjusts for the numerical flaws discussed 

above. 

e. The CPP does not account for deviations from historical norms. 

The commenters said the CPP uses an unrealistic assumption in its calculations by failing to 

account for the expansion of RPS requirements that are not within historical norms of 

deployment. The commenters added the CPP could create an unintended consequence of drivingup costs for RE resources. The CPP assumes that costs associated with implementing the BSER 

would be "reasonable" by analyzing historical RPS compliance costs. The commenters said RE 

generation at the levels represented in the best practices scenario can be achieved at reasonable 

costs; this finding has been confirmed with more recent RPS cost data, including a report that 

determined 2010-2012 retail electricity price impacts due to state RPS policies to be less than 

two percent, with only two states experiencing price impacts greater than three percent. The 

commenters said the CPP evaluation does not take into consideration the cost suppression effect 

of the federal Production Tax Credit and the Investment Tax Credit, which expire at the end of 

2013 and 2014, respectively. The commenters added as RPS requirements continue to grow over 

time, it is possible that RE may be difficult or infeasible to procure due to the technical or 

economic availability of RE resources. The commenters said most states address these potential 

constraints through RPS policies containing force majeure and annual compliance payment 

provisions that address resource availability, as well as cost cap provisions that address unusual 

pressure for cost increases to ratepayers. 

f. The CPP does not include Ohio's force majeure or cost-cap provisions in calculating the RE 

target. 

The commenters said Ohio includes force majeure and cost-cap provisions in its alternative 

energy rules that are codified in the state statute. The commenters said an electric utility or 

electric service company may modify its RPS compliance obligation, based on the demonstration 

of the electric utility or electric service company. The commenters said at the time of requesting 

such a determination from the commission, an electric utility or electric services company shall 

demonstrate that it pursued all reasonable compliance options including, but not limited to, 

renewable energy credit (REC) solicitations, REC banking, and long-term contracts. The 

commenters said an electric utility or electric services company may not be required to fully 
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comply with a specific RPS benchmark if determined that the cost cap provisions have been met 

based on proof provided by the electric utility or electric service company: An electric utility or 

electric services company may file an application requesting a determination from the 

commission that its reasonably expected cost of compliance with a renewable energy resource 

benchmark, including a solar energy resource benchmark, would exceed its reasonably expected 

cost of generation to customers by three percent or more. The commenters said the process and 

timeframes for such a determination shall be set by entry of the commission, the legal director, 

deputy legal director, or attorney examiner. The commenters said if the commission makes a 

determination that a three percent provision is triggered, the electric utility or electric services 

company shall comply with each benchmark up to the point that the three percent increment 

would be reached for each benchmark. 

Commenters stated the CPP's floor-based approach for setting Ohio's RE targets is faulty. The 

commenters said the CPP uses US EIA's 2012 net generation from RE sources (wind, 

hydroelectric conventional, other biomass, wood and wood derived fuels, and solar thermal and 

photovoltaic) for the total electric power industry in Ohio. The commenters said if Ohio's goal is 

modified to include specific floor-based requirements it would limit the ability of the state to 

create a plan for compliance with the state goals, and would operate contra to the flexibility 

principles preached by US EPA in developing this plan.

Comment 259: OH - BB1 HRI

Response 259: See section V.C. of the final rule preamble of the CPP for the EPA’s response to 

this comment and more information about Building Block 1.

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

Commenters stated many Ohio facilities have already implemented many of the heat

rate improvements cited by U.S. EPA; the improvements cannot be achieved again, but U.S. 

EPA has included them in calculating a reduction target. The commenters said the following 

projects have all taken place and should be addressed in Ohio's targeted reductions: 

• High Pressure Turbine improvements on multiple units utilizing state of the art 

computational techniques; 

• Rebuilt Cooling Towers for 3 Supercritical Units to improve heat rejection to 

reduce backpressure on the turbine for more efficient operation; 

• Replace Air Heater Baskets and Seals as needed to reduce wasted energy by 

recycling heat back into the boiler that would otherwise go to the stack; 

• Repair and/or Replace Feedwater Heaters as needed to allow energy within the 

steam to be returned to the boiler rather than discarded in the condenser; 
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• Repair Condensers as needed to keep turbine backpressure low promoting higher 

efficiency but also keep contaminated cooling water out of the boiler and turbine 

cycle; and 

• Any additional types of projects. 

Comment 260: OH - BSER (BBs 2, 3, 4)

Response 260: See sections V.A., V.D., and V.E. of the final rule preamble of the CPP for the 

EPA’s response to this comment and more information about Building Block 4, 2, and 3.

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

Commenters stated U.S. EPA's proposed rule has emission reduction targets based upon the 

assumption that building blocks 2, 3, and 4 can be implemented by a state as a part of its 

implementation plan; for the state of Ohio, that is inapplicable. The commenters said in regard to 

building block 2 concerning the dispatch of electricity, the state of Ohio has no authority nor can 

it by itself craft the authority to dictate the sale or purchase of electricity. The commenters said 

the dispatch of electricity is controlled by independent system operators beyond the authority of 

the state's lawmaking; further, because Ohio is a deregulated generation state, the state has no 

regulatory authority over the generation of electricity. The commenters said simply put, Ohio 

cannot dictate to independent system operators or consumers from which electricity generator 

they purchase; all of the emission reduction targets calculated from this sector should be 

removed from Ohio's BSER. 

Commenters stated Ohio faces a similar problem with the requirement of renewables as BSER; 

while the state has an existing renewal portfolio standard ("RPS") program, the program requires 

the generators to construct or otherwise invest in renewables. The commenters said the state 

cannot dictate the dispatch or purchase of this renewable generation; Ohio may be able to require 

the generation industry to build a certain amount of renewable assets but it has no mechanism by 

which to require others to either dispatch or purchase the electricity. 

Commenters stated as with building blocks 2 and 3, Ohio has no authority to create an energy 

efficiency mandate for all consumers which could be enforced to lower demand. The 

commenters said the proposal is impractical both legally and practically and even if such 

statutory authority could exist, the ability to create a program that would have enforceable 

energy use targets is almost impossible. 

Commenters stated all three of the last three building blocks, in addition to being "outside the 

fence line,'' are as impractical as they are illegal for creating a state implementation plan. The 

commenters said U.S. EPA cannot create emission reduction targets for the state of Ohio by 

considering what reductions could be achieved by these types of programs. The commenters said 

U.S. EPA should set BSER for the state of Ohio based on what can be achieved inside the fence 

line (which is, essentially, what could be achieved under building block 1) and then allow the 

state to, as best it can, achieve those reductions through a flexible SIP implemented by the state; 

however, U.S. EPA cannot use the other possible building blocks as a part of setting BSER.
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Building Block 4 -- Energy Efficiency 

Commenters stated based on an analysis of observed and expected energy efficiency 

achievement in 12 states, EPA determined that the "best practices" performance target for all 

states should be 1.5 percent. The commenters said EPA assumes that the energy efficiency

component of the rate equation begins in 2017, and states can increase energy efficiency 

achievements over time to reach a rate of 1.5 percent annually. The commenters said given 

Oregon's long-term commitment to acquiring energy efficiency, the commenters are concerned 

that EPA's methodology did not adjust the energy efficiency potential by the amount of 

conservation previously acquired or the amount of conservation that is available. The 

commenters said this may have the effect of requiring a state like Oregon, with established and 

robust conservation programs, to acquire conservation at a much higher cost (non-cost effective). 

The commenters said clarification is needed on the type of conservation that would meet the 

federal standard. The commenters said adjust recommendations for a state by the cumulative 

amount of conservation previously acquired and/or by the amount of achievable conservation 

potential in that state. 

State RE and EE Programs - RPS Changes 

Commenters stated in developing goals, U.S. EPA incorrectly applied outdated Ohio law to 

develop Ohio RE and East Central regional goals; specifically, U.S. EPA appears to have used 

Ohio Senate Bill (SB) 221 as a baseline for Ohio's state plan. The commenters said on September 

12, 2014, SB 221 was replaced by SB 310; the revised RPS outlined in SB 310 reduces long term 

targets and freezes the annual benchmarks for RE and solar energy resource development for two 

years. The commenters said by using outdated and incorrect benchmarks, U.S. EPA has inflated 

Ohio goals and the goals of states within the East Central region; this must be corrected. 

Commenters stated SB 310 created an Energy Mandates Study Committee in an effort to: ensure 

Ohio customers have access to affordable energy; incorporate as many forms of inexpensive, 

reliable energy sources as achievable; better understand how energy mandates impact jobs and 

the economy of Ohio; minimize government mandates; and ensure Ohio's current law is not 

unrealistic or unattainable. The commenters said a committee will study Ohio's RE, EE, and peak 

demand reduction mandates and finalize a recommendation report by September 30, 2015. The 

commenters said the potentially revised RPS and EE goals for Ohio, if enacted, will be in effect 

after U.S. EPA projects finalization of CPP rule; as a result, the targets established by CPP will 

be based upon incorrect potential EE/RE assumptions for Ohio. The commenters said U.S. EPA 

must revise the analysis for Ohio and the East Central region to reflect SB 310 and not SB 221. 

Comment 261: OH - Alternative target generation for wind power

Response 261: See section V.E. of the final rule preamble of the CPP for the EPA’s response to 

this comment and more information about Building Block 3.

The following are summaries of the specific public comments under this comment:
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Commenters stated the alternative target generation for wind power in Ohio, 11,663,046.41 MWh, is overly optimistic; this value is approximately half of the NGCC power generated in 2012 in 

Ohio, when natural gas prices were historically low. The commenters said using the EIA 

capacity factor for onshore wind, 0.34, Ohio estimates that the target appears to call for 3,916 

MW of wind power in the state. The commenters acknowledged that there is some additional 

potential for wind power in the state, this estimate is overly optimistic; even if such a large 

amount of wind capacity could be built, such generation could not be relied upon for base load 

power, and would be available to only a limited portion of the grid when dispatched; thus, the 

projected wind power could not realistically replace gas or coal-fired generation in a sustained 

base load capacity. The commenters said although Ohio may have additional wind generation 

potential, the development of such capacity relies upon federal subsidies for construction and 

utilization; without the federal subsidy (and a federal commitment to provide this subsidy until 

2030 and beyond) little new generation capacity will be built.

Comment 262: OK - general BSER

Response 262: 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 stated the CAA authorizes EPA to implement a best system of emission reduction 

as part of state guidelines; citing that authority, EPA devised a system to calculate state 

emission-reduction targets, referred to as its four Building Blocks. Those four Building Blocks 

are: 

• Building Block 1 - Improve heat rates at coal-fired EGUs by 6 percent; 

• Building Block 2 - Increase operation of existing natural-gas combined cycle 

units ("NGCCs") to a 70 percent capacity factor (up from a state average of 43 

percent in Oklahoma); 

• Building Block 3 - Increase deployment of zero-emitting renewable energy 

("RE") generating resources (up to 20 percent in Oklahoma); 

• Building Block 4 - Offset fossil-based generation by increasing deployment of 

end-use energy efficiency ("EE") measures (up to 10 percent for Oklahoma) 

Commenters said Oklahoma's overall state target is a 43 percent reduction below the 2012 

baseline rate; that number was reached after EPA chose to set targets in accordance with the high 

end of ranges established within each Building Block. The commenters said once the Building

Blocks were added up, the result is an unrealistically high and largely unattainable state goal that 

does not provide Oklahoma or its EGUs with meaningful flexibility in their compliance efforts. 

The commenters said a better approach would be for EPA to support compliance by setting 

lower targets in line with results achieved by demonstrated technology and in keeping with 
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Section 111(d) language; then, if it wants to, EPA could incentivize higher rate reductions 

without compromising much needed flexibility. 

Comment 263: OK - BB2

Response 263: See section V.D. of the final rule preamble of the CPP for the EPA’s response to 

this comment and more information about Building Block 2 and the CO2 Emission Performance 

Rate and Goal Computation TSD for CPP Final Rule supporting the final CPP.

EPA does not apply capacity factor increases at the unit-level, but rather at the state-level at 

proposal and the regional level in the final CPP. In the final CPP, EPA is assuming the 

1,018,724 MWh of existing generation for the three units and a reported capacity of just under 

300 MW, so the values feeding the regional calculation seem to be consistent with those 

provided by commenters. EPA has a summer capacity of 94 MW for each unit, so the baseline 

capacity factor estimation evidenced in Appendix 1 is 41% for the three units.

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

Commenters stated as a threshold matter, EPA applied incorrect capacity factors for Western 

Farmer's Anadarko NGCC Units 4, 5, and 6; EPA applied a 19 percent capacity factor for each 

of these units, but should have applied a 38 percent capacity factor for each of these units. The 

commenters said consistent with Western Farmers' January 2013 report to the Generating 

Availability Data System, the 2012 capacity factor for Anadarko Units 4, 5, and 6 is the product 

of the following calculation: (1,018,724 MWh / (8,724 hours * 300 MW)) * 100 = 38.65%. The 

commenters said by applying the incorrect capacity factor, EPA overestimated the capacity 

presumed to be "available" for redispatch and arbitrarily lowered the Oklahoma emission rate 

goal.

Comment 264: OK - BB3 RE

Response 264: See section V.E. of the final rule preamble of the CPP for the EPA’s response to 

this comment and more information about Building Block 3 and the CO2 Emission Performance 

Rate and Goal Computation TSD for CPP Final Rule supporting the final CPP.

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

Commenters stated that in correcting the RE Goal for the South-Central Region to 12 percent by 

including the Texas RPS in the region's goal calculation, and correcting a numerical error in the 

Kansas RPS goal. The commenters said that a Renewable Energy Goal for the South-Central 

Region of 12 percent is a more accurate representation of an achievable goal. The commenters

said the original option described in the Proposed Rule, i.e., using the average of states' RPS to 

set a goal, is more realistic, as it represents the expertise of states and is based on a more realworld scenario with diverse factors impacting development; therefore, the original option with an 

RE Goal based upon existing RPS is preferred, and the commenters requested that EPA correct 
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the South-Central Region RE Goal to 12 percent as specified in the Kansas Department of Health 

and Environment (KDHE) comments.

Comment 265: OR - Although Oregon is an importer of significant carbon-intensive generation, 

the EPA has characterized Oregon as a net exporter

Response 265: For the EPA’s response to this comment, see the CO2 Emission Performance 

Rate and Goal Computation TSD for CPP Final Rule supporting the final CPP. As building 

block four is no longer in the quantification of BSER, EPA does not make any judgement on the 

electricity importer/exporter status of a unit in the final CPP.

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

Commenters stated that the EPA has identified eight fossil-fuel EGUs in Oregon that are subject 

to the Proposal; five of these EGUs are owned by Oregon's investor-owned utilities and are, in 

part, used to serve a portion of their Oregon loads. Commenters indicated that although Oregon 

is an importer of significant carbon intensive generation, the EPA has characterized Oregon as a 

net exporter of generation, largely because of Federal Columbia River Power System (FCRPS) 

generation. Commenters noted that as a result of Oregon's net-exporter status, the EPA does not 

apply a net import factor to Oregon's BB4 BSER determination, resulting in an unadjusted Block 

Four goal that represents 1.5 percent of all statewide load. Commenters said on average, 

however, these five in-state, investor-owned EGUs only make up roughly 12 percent of the total 

generation used to serve Oregon load. 

Comment 266: OR interim goal unreasonably stringent - Boardman plant will close year later 

per agreement with the EPA 

Response 266: See section I.A. of the final rule preamble of the CPP and the CO2 Emission 

Performance Rate and Goal Computation TSD for CPP Final Rule supporting the final CPP for 

the EPA’s response to this comment.

Moreover, EPA has adjusted its start date for the compliance period to 2022. Therefore, the 

Boardman closure will occur prior to the start date of the CPP compliance requirements.

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

Commenters stated the Boardman Plant will cease burning coal on December 31, 2020 under a 

federally-enforceable agreement approved by EPA. The commenters said the Boardman 2020 

Plan was a collaborative effort between PGE, state regulators, customers, environmental groups 

and EPA to benefit the environment and customers; however, EPA's 111(d) proposal effectively 

assumes Boardman will shut down on January 1, 2020 based on the mistaken assumption that 

there is currently sufficient gas capacity in Oregon to displace Boardman's generation. 

Commenters said as a result, the proposal penalizes Oregon for leadership action on carbon 

emissions, and makes Oregon's interim goal unreasonably stringent due to a timing mismatch of 
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one year. Commenters said EPA can correct this issue in a number of ways: i) eliminating the 

interim goals and allowing states to determine their own emission reduction trajectories to 

achieve the 2030 goals, ii) modifying the interim goals to allow states to more gradually meet the 

final goal, or iii) applying a regulatory adjustment to coal-fired plants that have already 

committed to enforceable retirement dates. 

Commenters stated the key features that helped the Boardman 2020 Plan achieve broad support 

include: 

• A state-adopted agreement with broad and diverse stakeholder support; 

• An enforceable agreement to end coal operations by a date certain (December 31, 

2020); 

• A reasonable amount of time before the end of coal operations to address 

concerns regarding community impacts, including jobs at the facility, replacement 

of the Boardman Plant that considers cost to customers, reliability and resource 

diversity, and consistency with Clean Air Act requirements; 

• Interim emission controls that appropriately address human health and 

environmental impacts for the remaining period of coal-fired operations; 

• A robust resource planning process that considers low carbon replacement 

resources among the viable alternatives; and 

• A determination by the OPUC in PGE's 2009 IRP that the Boardman 2020 Plan 

represented the least cost, lowest-risk plan for PGE's customers. 

Commenters stated in addition to the incorrect assumption that Oregon has excess NGCC 

capacity available to displace Boardman, the proposal's assumption that all of Boardman's 

generation will be displaced prior to 2020 creates an interim goal for Oregon that is unreasonably 

stringent. The commenters said the Clean Power Plan's assumption that all of the emission 

reductions from Building Blocks 1 and 2 happen prior to the interim compliance period creates 

an emissions trajectory that resembles a cliff. 

Commenters saw three ways to correct the proposal's treatment of the Boardman Plant: 

1. Apply a regulatory adjustment to account for coal plants that committed to enforceable 

retirement dates prior to the Clean Power Plan proposal. The commenters said the rule 

could stipulate that coal plants with federally approved and enforceable plans to retire 

between 2020 and 2029 or a "book life" that ends between 2020 and 2029 are not subject 

to Clean Power Plan regulations. The commenters said alternately, the final rule could 

amend state goals to account for their emissions prior to their agreed-upon retirement 

dates.
287

2. Modify the glide path and interim goals to allow states to more gradually meet the final 

goal. The commenters said modifying the glide path and interim goals such that states are 

not required to achieve the majority of emission reductions prior to 2020 could mitigate 

many of the issues Oregon faces with regard to the Boardman Plant. The commenters 

said for a modified glide path to work for Oregon and properly incorporate the early 

action to end coal-firing at the Boardman Plant, the 2020-2029 period must include at 

least one full year of Boardman's average annual emissions; the calculation of the interim 

goal could include Boardman's full generation and associated emissions during calendar 

year 2020; the state goals could assume that no coal plant's output is displaced by more 

than 90% in the interim period; or the interim period could begin on January 1, 2021 or 

thereafter. 

3. Commenters said allow states to begin meeting interim goals as soon as EPA approves 

their compliance plans; this approach has the added benefit of eliminating the proposal's 

inherent incentive to delay investment in renewable energy and energy efficiency until 

2020. The commenters said similarly, the final Clean Power Plan could apply a "floor" 

and "ceiling" to the amount of a coal plant's output displaced by NGCCs; a ceiling of 

90% or less of a coal plant's output being displaced by NGCCs would hold Oregon 

harmless for maintaining the timeline of the Boardman 2020 Plan. 

4. Allow states to determine their own emission reduction trajectories to achieve the 2030 

goals. The commenters said states are best positioned to manage the transition of the 

generating fleet to meet the final goals established by the Clean Power Plan; the final rule 

should eliminate the interim goals and instead require states to propose emission 

reduction trajectories to EPA in their state plans. The commenters said giving states the 

flexibility to appropriately consider the cost and reliability implications - including costs 

resulting from significant job and other losses in communities that are often highly reliant 

on local power plants as economic engines, non-air environmental impacts, the remaining 

useful life of units scheduled for retirement, and the implications of a massive shift to 

different generating resources for much of the electricity supply - provides a possible 

avenue for properly recognizing early action to retire coal plants. 

Comment 267: OR - RE

Response 267: See section V.E. of the final rule preamble of the CPP for the EPA’s response to 

this comment and more information about Building Block 3 and the CO2 Emission Performance 

Rate and Goal Computation TSD for CPP Final Rule supporting the final CPP.

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

Physical Location

Commenters stated in determining the emission reductions possible from renewable resources, 

the proposal establishes annual renewable energy targets based on the physical location of 

renewable generation; the commenters said this assumption distorts the proposal's goals for 
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Oregon and creates a potential compliance conflict between Oregon and the states that currently 

use the renewable energy produced in our state for RPS compliance in theirs. 

Commenters stated though the proposed rule bases most of its renewable energy assumption on 

RPS policies, the proposal relies upon the physical location of generation to establish state goals. 

The commenters said the vast majority of RPS policies require utilities (or "load-serving 

entities") to meet a percentage of their retail electric sales with renewable resources. The 

commenters said by and large, state RPS policies do not dictate that the renewable resources that 

utilities use to meet their RPS obligations must be physically located in the same state as the 

customers that benefit from and pay for the RPS policy. 

Commenters stated by basing the renewable energy assumptions on the physical location of 

generation, EPA introduces several problems; first, EPA uses existing renewable projects to set 

goals for one state, when those projects today are used by other states for RPS compliance. The 

commenters said as the proposal currently stands, it is unclear which state would be able to use 

such a project for 111(d) compliance purposes. The commenters said the proposed rulemaking 

states that "consistent with existing RPS policies, a state could take into account all of the CO2 

emissions reductions from renewable energy measures implemented by the state, whether they 

occur in the state or in other states." The commenters said that approach may make sense when 

the renewable resources in question have not been included in the calculation of a state's goals; 

however, when a state's target is based on the physical presence of a resource within its borders, 

it should also have the ability to use that resource for compliance purposes. 

Commenters stated if EPA is going to base its assumption on the physical location of generation, 

the physical location of all generating resources must be properly defined. The commenters said 

the proposal assigns nearly all of the generation from hydropower facilities located on Oregon's 

border to Oregon. The commenters said if generation from those projects - which span the 

borders between Oregon and neighboring states - were evenly split between Oregon and its 

neighbors, the proposal would cap Oregon's renewable target at 9.6 million MWh rather than the 

proposal's target of 12.6 million MWh.

Commenters stated six out of seven dams located on Oregon's borders are fully allocated in 

EPA's eGRID dataset to Oregon's 2012 generation. The commenters said Bonneville Dam, the 

Dalles Dam, John Day Dam, and McNary Dam are four federally-owned, hydroelectric projects 

located on the section of the Columbia River that acts as the border between Oregon and 

Washington. The commenters said John Day and The Dalles are the fifth and seventh largest 

dams (by MW capacity) in the nation. The commenters said all of the energy produced by these 

four dams is allocated to Oregon's 2012 generation in the eGRID dataset used by EPA to develop 

the emission goals. The commenters said of the three dams (Browlee, Oxbow, and Hells 

Canyon) located on the section of the Snake River separating Oregon from Idaho, two are 

allocated to Oregon and one to Idaho. 

Commenters stated together, the generation from these six dams (Bonneville, the Dalles, John 

Day, McNary, Browlee, and Oxbow) was more than 30 million MWh in 2012, and all of it was 

applied to Oregon's 2012 baseline generation for use in Building Blocks 3 and 4. The 

commenters said under Building Block 3's in-state generation based methodology, this 

generation causes Oregon's renewable goal to increase by over 6 million MWh, an amount 
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greater than is necessary to serve the entire city of Portland annually. The commenters said 

assigning the six dams in this manner distorts Oregon's renewable goal in an arbitrary manner 

and should be corrected. The commenters said the power that the Bonneville Power 

Administration (BPA) generates from the four dams on the mainstem of the Columbia River 

served customers in the four Pacific Northwest states in 2012 as follows: 4% of the power served 

Montana customers, 6% served Idaho, 24% served Oregon, and the remaining 67% served 

Washington. Commenters said given this historic allocation, splitting the generation evenly from 

the projects physically on the border between Oregon and Washington states is, at the very least, 

a reasonable approach. 

RE targets do not match targets in existing state RPS plans 

Commenters stated the proposed renewable targets for many states do not closely resemble the 

renewable generation required from the RPS programs that the building block is based on. The 

commenters said for example, building block 3 caps Oregon's assumed non-hydro renewable 

generation at 12.6 million MWh, or 21 percent of the state's 2012 generation. The commenters

said Oregon's actual RPS obligation, however, is calculated as a percent of retail sales. The 

commenters said according to EPA's own data, 21 percent of the state's retail electric sales in 

2012 would be 9.6 million MWh. The commenters said Building block 3 caps California's 

renewable generation at 41.2 million MWh (21 percent of 2012 in-state generation), but 21 

percent of 2012 retail electric sales would be 53.4 million MWh.

Comment 268: OR - affected units

Response 268: Although not an applicability determination, EPA did not consider Cary 

Generating Station a likely affected EGU in its baseline.

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

Commenters stated in the proposal, EPA includes "under construction" natural gas combined 

cycle (NGCC) units to calculate state goals. The commenters said PGE is currently constructing 

the Carty Generating Station near Boardman, Oregon, and the commenters asserted that Carty is 

a 111(b) resource and not a 111(d) resource. The commenters said EPA presumably excluded 

Carty from the establishment of Oregon's Clean Power Plan goals because it agrees with our 

understanding of Carty's classification. The commenters said on September 9, 2014, PGE's 

outside counsel sent a letter to EPA asking for clarification on the determination that Carty is a 

111(b) resource subject. The commenters said EPA should clarify that the Carty Plant is a 111(b) 

resource and not covered by 111(d). The commenters said if EPA determines that Carty is among 

the resources that must comply with the Clean Power Plan, then EPA must include Carty's 

generation and emissions in setting Oregon's goal as it has for "under construction" NGCC units 

in other states. 

Comment 269: OR - general goal comments
290

Response 269: For the EPA’s response to this comment, see sections VI and VII of the final 

preamble and the CO2 Emission Performance Rate and Goal Computation TSD for CPP Final 

Rule supporting the final CPP.

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

Commenters appreciated the opportunity to comment on EPA's proposed Clean Power Plan. The 

commenters said as these comments have illustrated, the focus is to ensure that the carbon 

intensity goals EPA sets for Oregon's existing power sector are fair, reasonable, accurate, and 

credit the action the electric power customers and state are taking to address climate change. The 

commenters said the proposed rule contains technical and factual errors, incorrect assumptions, 

and unclear language that need to be corrected to accurately reflect the state's responsibility for 

and contributions to national GHG reductions.

Comment 270: OR - The EPA should accommodate exceptional events outside the control of 

states, such as extreme or unusual weather events

Response 270: See section VIII. of the final rule preamble of the CPP for the EPA’s response to 

this comment. Also see section VI of the preamble and the CO2 Emission Performance Rate and 

Goal Computations TSD for a description of the hydro adjustment that EPA had made. This 

adjustments will facilitate compliance in hydro-intensive states where fossil generation is more 

sensitive to fluctuation from 2012 levels due to the predominance of hydro generation.

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

Commenters stated that the EPA should accommodate exceptional events outside the control of 

states that occur during the compliance period, such as extreme or unusual weather events that 

are significantly different from conditions during the baseline period. Commenters felt the threeyear rolling average (for compliance after 2030) should be tempered by an allowance for 

unusually unfavorable conditions that inhibit a state's ability to achieve the emission goal during 

a certain period. According to commenters, this is especially important for Oregon and states in 

the Northwest given their reliance on generation from a hydroelectric power system that is 

directly influenced by annual temperature and precipitation patterns. Commenters said this could 

become increasingly important in the future as weather patterns are expected to become more 

variable and generally less favorable for hydroelectric power generation in the region as the 

climate warms.

Commenters stated the EPA already provides a similar approach to avoid determining that areas 

of the country exceed the National Ambient Air Quality Standards by excluding air quality 

monitoring data collected during a period for which a state adequately demonstrates an 

exceptional event caused the exceedance. Commenters suggested that the EPA use a similar 

approach in the Proposal that would allow states to show that an exceptional event has created 

conditions that made it infeasible for the reliable generation and transmission of electricity to 

achieve emission reduction requirements in a specific compliance period.
291

Comment 271: PA should be able to meet target, already cutting emissions.

Response 271: The EPA appreciates the emission reductions the PA is achieving, please see the 

the CO2 Emission Performance Rate and Goal Computation TSD for CPP Final Rule supporting 

the final CPP for the revised goals.

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

Commenters stated that in Pennsylvania they already have some good ongoing models that will 

help the commenters to meet the state target of a 32 percent reduction of carbon intensity by 

2030. Commenters stated that since EPA used fairly conservative assumptions to generate its 

estimates of their renewable energy and energy efficiency potential, Pennsylvania could harvest 

significantly greater cost effective carbon reductions with increasing benefits.

Commenters noted that on the renewable energy front, while the state's alternative energy 

portfolio standard definitely needs to be strengthened, Pennsylvania is well positioned to ramp 

up. Commenters stated that even in its currently relatively modest form, the standard has already 

driven the installation of more than 1,300 megawatts of wind power, 25 wind farms, providing 

1.5 percent of the state's energy in 2013 and powering the equivalent of 300,000 homes.

Commenters stated that a solid solar power foundation has been established as 

well. Commenters stated that there are more than 440 solar companies in their state, employing 

2,900 workers and their installed solar capacity is 11th in the nation.

Commenters stated that they can give Pennsylvania more jobs, more energy savings, a more 

stable climate, and healthier families by meeting and exceeding the targets in the proposed plan.

Commenters stated America, as a whole, is only at 16 percent of the world's contributions; but in 

fact, since 2005 the power plant industry in Pennsylvania has cut their greenhouse gases by 14 

percent, a very notable contribution. The commenters said it's not the only reductions, points or 

submissions that have gone down in Pennsylvania. The commenters said SO2, according to DEP 

is down 68 percent, NOx by about 30 percent, and VOCS by 21 percent, and that's having a 

demonstrated impact on air quality with fewer and fewer ozone action days being called each 

year. 

Commenters stated research has shown that over the next 40 years Pennsylvania can take the 

road to 100 percent renewable power generation, create over 350,000 jobs in the process, and 

continue to save residents money on their energy bills as compared to the retentive fixation on 

fossil fuel.

Commenters stated Pennsylvania has already had some good ongoing models that will help PA 

to meet the state target of a 32 percent reduction of carbon intensity by 2030. The commenters

said in fact, since EPA used fairly conservative assumptions to generate its estimates 

of renewable energy and energy efficiency potential, Pennsylvania could harvest significantly 

greater cost effective carbon reductions with increasing benefits.

Commenters stated EPA's goals for Pennsylvania are achievable. The commenters said 

Pennsylvania has the tools to achieve the proposed goals and to grow its economy and without 
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the need to retire additional power plants. The commenters said low energy prices have forced a 

number of older coal plants to retire since the 2012 base year, and a number of others are 

scheduled to retire in the next few years; this is in part the result of PA's aging fleet. The 

commenters said while coal-fired power plants nationwide tend to last 48 years, most of 

PA's plants are in their 60s when they close; this is also the natural result of PA's competitive 

energy markets combined with low natural gas prices. The commenters said First Energy 

President, James Lash, recognized this in testimony last year before a state Senate when he 

admitted that even without the EPA, his plants that were closing would still be losing money. 

The commenters said fortunately, newer and cleaner sources of power are already making up for 

the lost capacity and more is on the way; because of this, PA is on track to exceed EPA's 

expectations for re-dispatch of coal generation to cleaner sources. 

Commenters stated Pennsylvania is also likely to exceed expectations related to PA's nuclear 

resources. The commenters said all five of PA's nuclear generating stations are currently licensed 

until after the 20/30 compliance period. The commenters said PA may also see additional nuclear 

capacity from uprates at existing facilities; such uprates, like any additions to nuclear capacity, 

will offset reductions needed from other sources. The commenters said PA's alternative energy 

portfolio standards are all also currently providing more renewable energy than EPA expected, 

and data suggests that EPA's goals could be met with modest additional effort. The commenters

said new solar and wind capacity will not only bring more clean domestic energy to the market, 

but recent modeling has shown that construction of these resources creates more jobs than 

building the equivalent fossil fuel capacity. 

Commenters stated energy efficiency, however, may be the star of the show. The commenters

said the PA Act 129 program sets specific targets for energy efficiency improvement across the 

state. The commenters said all electric distribution companies ultimately have met their phase 

one goals and are now working on phase two. The commenters said that success is good news, 

but the best news is that an independent evaluator, using a total resource cost test, found that 

these programs return $3 in direct economic benefits to consumers for every $1 spent; and that 

doesn't include health and environmental benefits. The commenters said the evaluator also 

examined 579 energy efficiency measures and found that Pennsylvania could more than double 

the reductions EPA expects and do so and still save money.

Commenters stated PA must choose to take full advantage of all the opportunities presented to us 

through the Clean Power Plan such as building on the success of renewable portfolio standard 

that is making strides towards generating 18 percent of the state's electricity and using renewable 

energy sources by 2021. The commenters stated while progress on the Lake Erie wind project is 

taking longer than expected, PA is optimistic that the leadership of the Lake Erie Energy 

Development Corporation and other stakeholders offshore wind will grow and become part of 

PA's energy portfolio. 

Comment 272: PA - BB3 RE & BB4 EE

Response 272: See section V.E. of the final rule preamble of the CPP for the EPA’s response to 

this comment and more information about Building Block 3 and the CO2 Emission Performance 
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Rate and Goal Computation TSD for CPP Final Rule supporting the final CPP for the final goals.

The EPA has determined that demand-side EE programs (proposed building block 4) are not a 

component of the final BSER. See section V.A.3 of the final rule preamble for discussion of this 

issue.

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

Commenters stated that the proposal requires Pennsylvania to increase its current renewable 

generation from two percent of total net generation to 16 percent. Commenters indicated that this 

represents an increase of approximately 35,000,000 MWh from renewable energy, which is 

approximately equal to the total net generation of Maryland in 2012. Commenters said that this 

result is due to the arbitrary regional growth factor set by the RPS of other states in their region, 

none of which exceed three percent of their total net generation in renewable energy. 

Commenters added that this unrealistic increase in renewable generation represents 48.4 percent 

of the proposed target for Pennsylvania.

Commenters stated increased generation from renewables comprises the single largest 

component in EPA's development of Pennsylvania's overall carbon emission rate target; 

specifically, under EPA's scenario, increased renewables would account for nearly 50 percent of 

the total carbon emission reductions needed to move Pennsylvania from its 2012 emissions rate 

to the 2030 target rate prescribed for it by EPA. The commenters said the sharp disparity 

between the inflated renewables target EPA used to establish Pennsylvania's emission rate goal, 

and the state's limited renewable energy potential relative to other states, is directly traceable to 

flaws in EPA's methodology for computing renewable energy targets. The commenters said these 

flaws produce biases both across regions of the country, as well as within the East Central region 

to which Pennsylvania was assigned, all of which work to the detriment of Pennsylvania. 

Commenters stated in order to meet EPA's renewable energy target, Pennsylvania would need to 

increase the amount of electricity it obtains from renewable sources by a multiple of eight times 

between 2012 and 2030. The commenters said this multiple exceeds what EPA is expecting of 

any other state in the country outside the East Central region to which Pennsylvania was 

assigned for purposes of developing renewable energy targets; outside the East Central region 

only seven states would even be expected to increase renewables as a percentage of total 

generation by a factor as much as four times; another fifteen states would only be expected to 

increase renewables as a percentage of generation by a factor of two times or less, or in some 

cases not at all. The commenters said there is a stark disconnect between Pennsylvania's limited 

potential - relative to other states - for expanding its renewable generation capacity, and the 

highly ambitious rate of increase in renewable energy - exceeding that of nearly every other state 

- which EPA assumed for Pennsylvania in developing the state's overall emission rate target. 

Commenters stated EPA relies largely on a Black & Veatch Report titled Economic Impacts of 

Renewable Energy in Pennsylvania (2004) as the basis for many of its PA-specific 

recommendations regarding the costs associated with deployment of RE resources. For more upto-date information, the commenters recommended the PAPUC annual AEPS/Act 129 Report. 

The commenters said the latest report estimates that the cost to meet the 2021 18% AEPS target 

will be $149.2 million, of which $146 million will be attributed to meeting the 8% Tier I 

requirement.
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Commenters stated Pennsylvania was assigned to the East Central region which also includes 

Delaware, District of Columbia, Maryland, New Jersey, Ohio, Virginia, and West Virginia; EPA 

then calculates a "renewable generation target" for each region, from which it derives an "annual 

growth factor" that would allow the region as a whole to reach its renewable target in 2029. The 

commenters said this regional annual growth factor is then applied to individual states' historic 

2012 renewable levels to calculate each state's interim and final renewable targets. 

Commenters said the disparate annual growth factors developed for each of the eight regions - in 

particular, the annual growth factor for the East Central region, at 17 percent, is the highest 

among all eight regions in the country. The commenters said as a consequence, several states in 

the East Central region - including Pennsylvania, Maryland, New Jersey, and Ohio - would need 

to grow their renewables by eight times or more to achieve their ultimate renewables targets. 

1. EPA's Flawed Methodology Produces Biases Between Regions of the Country that Work 

to the Detriment of Pennsylvania and Other States in the East Central Region. 

2. EPA's Flawed Methodology Produces Biases Within the East Central Region by Ignoring 

Pennsylvania's Role as the Region's Predominant Producer and Consumer of Electricity 

and Imposing on Pennsylvania the Policy Choices of Neighboring States with Very 

Dissimilar Economic and Energy Profiles. 

3. Correcting for the Biases Created by EPA Within the East Central Region Produces a 

More Plausible and Equitable Renewables Target That Reflects Pennsylvania's Own 

Policy Choices and Gives Full Consideration to the Conditions of the State's Electricity 

Market. 

Commenters stated if, however, EPA remains committed to relying on RPSs to establish regional 

renewables targets, a more plausible approach, which dramatically reduces the biases inherent in 

its equal weighting method, would be to weight each state's RPS to reflect its proportionate share 

of overall generation in the region; using this more reasonable and equitable approach would 

further reduce the renewable target for the East Central region from 12 percent to less than 9 

percent. The commenters said this 9 percent regional renewable target translates to a regional 

annual growth factor of 12 percent (versus 17 percent using equal weighting of state RPSs). The 

commenters said applying this more realistic regional growth factor would then require 

Pennsylvania to increase its reliance on renewables by 4.3 times (versus eight times under EPA's 

approach) to achieve its final renewables target. 

Commenters stated, the PAPUC, pursuant to the Electricity Generation Customer Choice and 

Competition Act, established one of the first successful retail customer choice programs in the 

nation. Commenters said, currently, 38% of Pennsylvania customers participate in the customer 

choice program. Commenters said, the PAPUC also oversees a vibrant market in alternative 

energy and energy efficiency by virtue of passage of the Alternative Energy Portfolio Standards 

(AEPS) Act of 2004 and Act 129 of 2008. Commenters said, Pennsylvania, like many other 

states, has implemented an aggressive AEPS program for promotion of renewable resources and 

energy efficiency measures. Commenters said, EPA's proposed CAA Section 111(d) emissions 

standards purport to regulate renewable energy (RE) resources under BB3 and demandside/energy efficiency (DS/EE) programs under BB4. Commenters said, EPA's proposed targets 
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for both BB3 and BB4 are not credible and will be unattainable given current legislative 

constraints and structural and economic obstacles to further expansion of RE and DS/EE 

programs in Pennsylvania. 

Comment 273: PA - The EPA should ensure natural gas, coal waste, and trash are not allowed 

as electricity generating sources, and that only zero-emissions energy sources such as EE, wind, 

solar, and geothermal should be used for compliance credit

Response 273: See section VIII. of the final rule preamble of the CPP for the EPA’s response to 

this comment. Also see IV.D for a description of affected sources, and V.E for a description of 

renewable resources considered in block three.

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

Commenters stated Pennsylvania is off to a bad start, the commenters said the Pennsylvania 

Department of Environmental Protection's recommended framework for implementing the rule 

includes exemptions and credits for dirty types of energy that will greatly limit the rule's 

effectiveness. 

Commenters stated EPA should ensure that natural gas, coal waste, and trash have no place in 

this rule and that only zero-emissions energy sources such as energy efficiency, wind, solar and 

geothermal should be allowed to be used for credits in the program. The commenters said please 

ensure that Pennsylvania's implementation of the Clean Power Plan is designed and implemented 

in a way that truly cuts carbon pollution and protects public health. 

Comment 274: PA - PA is disproportionately and unfairly burdened

Response 274: See section I.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 generally supported EPA's approach, however is concerned with several elements 

that would disproportionately and unfairly burden the Commonwealth of Pennsylvania. The 

commenters said the transition to clean energy must include a pathway for multiple forms of

electricity generation including coal, nuclear energy and hydropower, as well as consider our 

manufacturing and industrial sectors. The commenters said Pennsylvania ranks fourth in coal 

production and coal provides about 40 percent of its electricity; moreover, the reliability and 

reasonable cost of coal-based electricity is critical to the energy-intensive industries in 

Pennsylvania (including steel, cement, pulp and paper, and glass) and to Pennsylvanians who 

must balance their household budgets. The commenters said PA needs to keep coal in the energy 

mix, but in a manner that reduces pollution. The commenters said coal is an important domestic 

resource that cannot simply be ignored for the sake of expediency.
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Commenters stated costs imposed by EPA's inflated renewables target cannot be mitigated by 

obtaining additional emission rate reductions from other building blocks. 

a) Coal Heat Rate Improvement. The commenters said in constructing Pennsylvania's 

overall emission rate reduction target of 575 lbs/MW, EPA included reductions of 77 

lh/MWh from building block 1, coal heat rate improvement; thus under EPA's scenario, 

increased efficiency at existing coal fired power plants would account for 13 percent of 

the total carbon emission reductions needed to move Pennsylvania from its 2012 

emissions rate to its 2030 target rate. 

Commenters stated that their assessment of how the Proposed Rule would affect 

Pennsylvania and their facility differs substantially from EPA's assessment. Commenters 

stated that in several areas, their analysis shows that EPA has over-predicted the amount 

of emission reductions that would be achieved through implementation of the Building 

Blocks. Commenters stated EPA projects that 77 lbs. CO2/MWh can be reduced in 

Pennsylvania through implementation of heat rate improvements ("HRI") at existing 

units. Commenters stated this level of reduction is unlikely to be achieved since many 

units in the State have already undergone modifications to improve their heat rates or 

they are already highly efficient. 

b) Natural Gas Redispatch. The commenters said in constructing Pennsylvania's overall 

emission rate reduction goal, EPA included reductions of 70 lbs/MWh from building 

block 2, redispatch from coal-fired EGUs to natural gas-fired EGUs; thus, under EPA's 

scenario, substituting generation from less carbon intensive natural gas EGUs for more 

carbon intensive coal EGUs would account for 12 percent of the total carbon emission 

reductions needed to move Pennsylvania from its 2012 emission rate to its 2030 target 

rate.

c) Energy Efficiency. In constructing Pennsylvania's overall emission rate reduction goal, 

EPA included reductions of 105 lb/MWh from building block 4, demand-side energy 

efficiency; thus, under EPA's scenario, reduced electricity generation, from the adoption 

of demand-side energy efficiency measures, would account for 18 percent of the total 

carbon emission reductions needed to move Pennsylvania from its 2012 emission rate to 

its 2030 target rate. 

Comment 275: PA's energy profile details 

Response 275: The EPA appreciates the information regarding PA’s energy profile.

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

Commenters stated Pennsylvania has a diverse energy profile; Pennsylvania energy sources 

encompass all forms of energy production including nuclear, coal, natural gas, waste-to energy, 

hydroelectric and renewables. The commenters said Pennsylvania is the fourth largest coal 

producer in the U.S. and produced 68 million tons of coal (bituminous and anthracite) in 2011. 

The commenters said the coal industry directly employs about 8,700 employees and indirectly 
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supports about 32,800 jobs such as employment in the state's coal-fired power plants and the 

railroad industry. The commenters said Pennsylvania's abundant coal reserves assure decades of 

reliable, low cost energy for the state and the region; coal consumption for electric generation in 

the state was 47,324,852 tons in 2011. 

Commenters stated Pennsylvania is also a national leader in the production of natural gas; natural 

gas production in the Marcellus region generally exceeded 15 billion cubic feet per day through 

August 2014. The commenters said Pennsylvania's Marcellus Region possesses the largest shale 

gas producing resources in the nation with over 100 rigs currently operating and each rig 

supporting more than 6 million cubic feet per day in new well production each month. The 

commenters said Pennsylvania's annual gross natural gas production, primarily from the 

Marcellus Shale, exceeded 2 trillion cubic feet in 2012, a 72% increase over 2011 

production; Pennsylvania's net energy generation by natural gas amounted to 41,792,165 MWH 

or 28% of the total generation in 2014. 

Commenters stated nuclear generation also represents a significant portion of Pennsylvania's 

energy profile; currently, there are five nuclear generation facilities operating in the state 

representing 7,000 GWH or 35% of net electricity generation. 

Commenters stated Pennsylvania also derives an increasing amount of electric generation from 

hydro-electric sources and renewables representing 162 GWH and 400 GWH respectively; these 

figures represent approximately 1.0% and 2.0% of Pennsylvania's electric energy generation. 

Comment 276: SC - Commenters questioned whether goals and methods are inaccurate

Response 276: For the EPA’s response to this comment, see sections VI and VII of the final 

preamble and the CO2 Emission Performance Rate and Goal Computation TSD for CPP Final 

Rule supporting the final CPP.

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

Commenters expressed concerns about whether current changes and proposed future actions can 

achieve the CO2 reduction goals that EPA has set for South Carolina, and that those goals have 

been incorrectly computed.

Commenters stated that South Carolina utilities have made significant changes to their 

generating fleet to comply with other regulatory requirements. Commenters said these changes 

have reduced emissions and have allowed utilities to continue to diversify their generation mixes. 

Commenters said in preparation of expected requirements to reduce criteria and air toxic 

pollutants, as well as anticipated CO2 regulations, all of the older, less efficient coal units 

(fourteen units in all) are to be shut down or switched to natural gas and operated as backup units 

by 2018. Commenters said almost all of these units' physical changes were completed before 

2012. Commenters said all remaining units (thirteen newer and more efficient ones) have 

complete suites of emission controls installed, reducing criteria and air toxic emissions to meet 

existing and expected regulations.
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Commenters stated that there are concerns with other building blocks you have recommended as 

well, in that they are not readily useful to South Carolina. Commenters said that although Santee 

Cooper and other utilities are promoting energy efficiency, more than a third of South Carolina's 

retail sales are to industrial customers. Commenters said it is not reasonable to assume that large 

increases in energy efficiency are available to this customer class; they are already doing all they 

can do to conserve. Commenters said achieving a 10 percent increase in energy efficiency 

savings in South Carolina as proposed in this regulation is not feasible.

Commenters stated that currently, South Carolina has the third most stringent reduction target of 

any state and the largest numerical reduction, from 1587 lbs. CO2/MWh to 772 lbs. CO2/MWh, 

a difference of 815 lbs. CO2/MWh. Commenters said that under the Proposed Rule, South 

Carolina would be required to reduce its emission rate by 51% relative to 2012. Commenters said 

in EPA's calculation of South Carolina's goal, the under-construction nuclear component 

accounts for 33% of the total reductions required from the affected fossil-unit rate. Commenters

said if the under-construction nuclear component were removed from the goal calculation, South 

Carolina's target rate would be 990 lbs. CO2/MWh instead of 772 lbs. CO2/MWh. Commenters

said that consequently, South Carolina's 2030 goal is 22% more stringent because of EPA's 

inclusion of under-construction nuclear.

Commenters stated that Santee Cooper has a direct interest in how EPA establishes South 

Carolina's state goal. Commenters said Santee Cooper owns existing affected fossil-fueled EGUs 

that will be required to implement performance standards whose stringency will be specifically 

based on the assumptions that EPA makes in calculating South Carolina's state emission goal. 

Commenters said that Santee Cooper also owns a 45% stake in the two V. C. Summer nuclear 

reactors that are currently under construction. Commenters said that EPA's fundamentally flawed 

approach to including under-construction nuclear generation in state goal-setting and compliance 

will directly affect Santee Cooper's investment in that facility. Commenters said that as a loadserving utility, Santee Cooper will also be affected by the increases in costs and by reliability 

issues that could result from the manner in which EPA establishes South Carolina's state goal.

Commenters stated that each of EPA's assumptions about the "building blocks" that comprise 

BSER are overly aggressive and based on arbitrary and erroneous assumptions - particularly as 

applied to South Carolina and Santee Cooper. Commenters said EPA should revise South 

Carolina's state goals to account for the significant problems with building blocks one through 

four.

Commenters stated that EPA's Alternate State Goals also suffer from flaws. Commenters said 

that while the Alternate State Goals use a 4% rather than a 6% assumption for heat rate 

improvements in block one, even that lower assumption significantly exceeds attainable levels at 

Santee Cooper's units and other affected coal-fueled EGUs within the State of South Carolina. 

Commenters said the Alternate State Goals' reductions in NGCC utilization (from 70% to 65%) 

in block two, and estimated annual energy efficiency savings (from 1.5% to 1%) in block four, 

similarly exceed the achievable levels in South Carolina. Commenters said the Alternate State 

Goals would still pose a substantial compliance challenge because they would become fully 

effective in 2025 with only a five-year averaging period (rather than a ten-year period in EPA's 

primary proposal). Commenters said the Alternate State Goals do not remedy the problems of the 

Proposed Rule. Commenters said EPA has no choice but to withdraw the Proposed Rule due to 
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arbitrary and grossly erroneous building-block assumptions used for computing South Carolina's 

state goals.

Comment 277: SC - formulas question

Response 277: EPA engaged frequenly with states and stakeholderds during the comment 

period. EPA has clarified its methodology in this final rule as described in Section VI and VII of 

the preamble as well as the CO2 Emission Performance Rate and Goal Computations TSD.

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

Commenters had questions about the formulas, and asked for clarification about the specific 

methodology for calculating SC's goal.

Comment 278: SD - Multiple comments about inaccurate baseline data affecting goal 

computation

Response 278: See section VI of the final rule preamble of the CPP and the CO2 Emission 

Performance Rate and Goal Computation TSD for CPP Final Rule for the EPA’s response to this 

comment. The Ben French facility has been excluded and based on comments, the EPA 

identified Deer Creek Station generators 01 and 02 as under construction - commenced operation 

in 2012 and is estimating incremental generation and emissions for the st ate reflective of a 

capacity factor assumption of 55% for these NGCC units.

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

Commenters expressed concerns that EPA's goal computation for South Dakota used inaccurate 

data.

Commenters stated that even if re-dispatch were workable in this setting, the South Dakota target 

would need to be adjusted because the lone combined-cycle unit did not begin operating until 

late 2012, resulting in an unrepresentative 1-percent capacity factor. Commenters said the 

combined-cycle unit should be considered an under-construction unit in the South Dakota target 

calculation, similar to the treatment of the combined-cycle units that began operation or 

construction in 2013, in other states.

Commenters stated that Otter Tail Power Company has long demonstrated best practices in 

environmental stewardship, and their cost-effective addition of renewables is ahead of the 

national curve. Commenters said before EPA issued its proposed Clean Power Plan, Otter Tail 

Power Company already had a plan to reduce carbon dioxide emissions intensity by 24% by 

2021. Commenters said they are concerned that faulty assumptions and arbitrary inconsistencies 

in the proposed rule, however unintentional, will strand hundreds of millions of dollars of recent 

clean energy improvements and counterproductively penalize Otter Tail and the State of South 

Dakota for being early adopters of clean energy resources and technology.
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Commenters stated that EPA's selection of an unrepresentative baseline year for South Dakota 

and its consideration of Deer Creek Station as a fully operational NGCC plant in calculating the 

state's baseline emissions threatens to shutter Big Stone Plant, which by 2016 will be among the 

less than 10% of coal plants in the nation using similar state-of-the-art technology for SO2, NOx, 

and particulate matter removal. Commenters said that not only would closing Big Stone Plant 

strand the considerable capital Otter Tail expended in good faith to modernize the facility, it will 

also threaten the company's ability to provide reliable energy to its customers, subjecting them to 

rate increases of about 20% to replace the plant.

Commenters stated that there are two issues related to the Ben French data represented in the 

EPA's eGRID data. Commenters said the 2012 year is not an accurate representation of Ben 

French's typical contribution to the state's coal generation because the unit began an economic 

outage on 8/31/2012 which lasted through the end of the year. Commenters said the CO2 

emissions calculated by EPA's emission factor are not as accurate as the CO2 emissions 

calculated under 40CFR98 (EPA's Mandatory Reporting Rule for Green House Gas emissions). 

Commenters said the 2012 source data should be adjusted to 2011 generation when the unit 

operated the entire year and the CO2 emissions have been adjusted to the 2011 40CFR98 

reported CO2 emissions.

Comment 279: SD - Goal computation involved flawed assumptions in BB1, BB2, and BB3

Response 279: See sections V.C., V.D., and V.E. of the final rule preamble of the CPP for the 

EPA’s response to this comment and more information about Building Blocks 1, 2, and 3 and the 

CO2 Emission Performance Rate and Goal Computation TSD for CPP Final Rule supporting the 

final CPP.

Deer Creek Station is categorized as under construction consistent with the comment.

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

Commenters discussed issues involving the use of Building Blocks 1, 2, and 3 in computing 

South Dakota's goals.

BB1. Commenters stated that under Building Block 1, EPA makes the assumption that every 

affected coal-fired generating plant can achieve an average heat rate improvement of 6 percent. 

Commenters said EPA further identifies that coal generating plants could achieve heat rate 

improvements through either best practices for operations and maintenance or equipment 

upgrades. Commenters said according to EPA's analysis, affected coal-fired generating plants 

could achieve, on average, a 4 percent improvement in heat rate through best operating practices 

and a 2 percent heat rate improvement through equipment upgrades. Commenters said that the 

application of national averages for heat rate improvements to each individual affected coal-fired 

generating plant is flawed, with South Dakota being a prime example of this flaw (as set forth in 

the following paragraphs). Commenters said EPA must use unit-specific data when applying 

Building Block 1.
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Commenters stated that South Dakota has one affected coal-fired generating plant, BSP, which 

would need to achieve the 6 percent heat rate improvement identified in Building Block 1. 

Commenters said this heat rate improvement is not technically achievable at BSP as identified by 

its owners. Commenters said that according to BSP's owners, "Big Stone [Plant] has a proud 

history of 'best operating practices' and efficiency upgrades." Commenters said the owners state 

"Big Stone Plant has already made or plans to make all applicable [heat rate improvements] 

identified by Sargent and Lundy." Commenters said the owners are in the process of installing a 

state of the art air quality control system (AQCS) to comply with EPA's Regional Haze and 

MATs rules. Commenters said the AQCS system will consume approximately 8 to 9 MWs of the 

energy produced by the plant, resulting in the degradation of the plant's heat rate by 1.7 percent.

Commenters stated that since EPA did not account for unit-specific circumstances when 

including the 6 percent heat rate improvement in South Dakota's goal computation, EPA's final 

goal calculation for South Dakota is in error. Commenters said EPA's assumed heat rate 

improvement of 6 percent for South Dakota's coal-fired generation cannot be achieved at the one 

affected coal-fired plant, BSP. Commenters said three factors that make the 6 percent heat rate 

improvement unattainable at BSP include: 1) the owners already implement best operating 

practices at the plant, 2) the owners already completed, or are in the process of completing, all 

applicable equipment upgrades identified by Sargent and Lundy, and 3) parasitic load from 

BSP's new AQCS will decrease the plant's heat rate by 1.7 percent. Commenters said that, based 

on these site-specific circumstances for Big Stone Plant, which make heat rate improvements at 

the plant not technically feasible, commenters recommended that EPA exclude Building Block 1 

from South Dakota's final goal calculation.

BB2. Commenters stated that under Building Block 2, EPA expects existing NGCC plants to 

ramp generation up to a 70 percent capacity factor, with the additional generation offsetting an 

equal amount of coal generation within the same state. Commenters said EPA's application of 

this block to South Dakota results in the largest reduction of emissions assumed possible by all 

four blocks. Commenters said that South Dakota is the perfect example of why this block is 

flawed.

Commenters stated that EPA's one-size-fits-all building block approach ignores the unique, realworld operation of the bulk electric system in each state. Commenters said that in South Dakota, 

only two units will be affected by EPA's proposal: BSP and DCS. Commenters said BSP is a 475 

MW coal-fired power plant owned by three IOUs. Commenters said DCS is a 324 MW NGCC 

power plant owned by Basic Electric Power Cooperative (Basin Electric). Commenters said the 

two plants operate in separate dispatch areas - BSP in MISO, DCS in SPP. Commenters said 

they serve independent loads, where BSP serves IOU customers and DCS serves cooperatives. 

Commenters said they also serve different purposes, where BSP provides base load power and 

DCS provides intermediate power.

Commenters stated that despite concluding "that increments of generation are to some extent

interchangeable" in the proposed rule, EPA's Building Block 2 assumes that all increments of 

generation within a state are fully interchangeable and that security-constrained economic 

dispatch (SCED) is prevalent throughout the bulk electric system. Commenters said this is not 

the case. Commenters said in South Dakota, increments of generation between BSP and DCS are 

not interchangeable for the reasons stated above. Commenters said the two plants operate in 
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separate dispatch areas, serve independent loads and different purposes, and will operate in 

different electricity markets. Commenters said in attempting to achieve EPA's proposed goal, 

increasing generation from DCS would not result in a decrease at BSP. Commenters said the 

application of Building Block 2 in South Dakota is not technically feasible, and EPA should not 

include it in determining the state's goal.

Commenters stated if Building Block 2 is not removed from the state's goal, EPA must correct 

major flaws in the baseline assumptions for DCS NGCC, at a minimum. Commenters said in the 

proposed rule, EPA assumes normal operation for DCS is at a 1 percent capacity factor because 

of the hours it operated in 2012. Commenters said this conclusion was despite the fact that it was 

under construction for more than half of that year. Commenters said DCS should be considered 

"under construction" with an assumed 55 percent capacity factor, similar to other new NGCC 

plants. Commenters said DCS is assumed to have a maximum capacity of 324 MW by EPA. 

Commenters said the plant is limited by an interconnection agreement of only 300 MW, 

consistent with the siting permit approved by the SD PUC. Commenters said these technical 

errors in EPA's proposal must be corrected in the final rule if Building Block 2 is used.

Commenters stated that Building Block 2 should not be applied to South Dakota's goal. 

Commenters said generation cannot be redispatched from the state's single coal-fired plant to the 

state's single NGCC plant. Commenters said if EPA chooses to ignore this fact, it must at least 

correct the technical errors mentioned above in the block's baseline assumptions for DCS.

BB3. Commenters stated that in calculating South Dakota's goal, EPA included all generation 

produced in the state. Commenters said that EPA has indicated that compliance may be based on 

ownership of the renewable energy certificates (RECs) associated with that generation, 

regardless of the state where it is physically located. Commenters said the calculation of a state's 

baseline in determining its goal, then, should also be based on which states actually have a legal 

claim to the environmental benefits associated with that generation.

Commenters stated that RECs were developed to facilitate the tracking of renewable energy, 

allowing purchasers of renewable energy to claim the attributes and benefits of that specific 

renewable resource. Commenters said each REC represents the claim to the environmental 

benefits associated with 1 MWh of renewable electricity. Commenters said that RECs have been 

tracked for more than a decade in this country for such purposes as complying with renewable 

portfolio standards and claiming the use of "green" energy in the production of goods. 

Commenters said REC tracking systems have been established nationwide to verify and provide 

integrity to those claims, as many RECs are sold separately (or unbundled) from the electricity 

they represent. Commenters said that most of these systems define a REC as including all 

environmental attributes (including the emissions reductions) associated with that generation. 

Commenters said if EPA allows states to claim the emission reduction benefits of renewable 

electricity generated within their state, they are technically claiming the same benefits as those 

held by the owners of those RECs. Commenters said this scenario would create confusion and 

uncertainty in the REC marketplace and in state RPS compliance programs as well. Commenters

said if EPA decides to base compliance on REC ownership, renewable baselines in Building 

Block 3 should be based on REC ownership location rather than generator location.
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Commenters stated that in South Dakota, approximately 24 percent of generation produced in the 

state came from wind energy in 2012. Commenters said that a large majority of the RECs 

associated with that wind generation is contracted to out-of-state utilities for compliance within 

their own states. Commenters said the Buffalo Ridge I and II projects in eastern South Dakota, 

which make up approximately 260 of the state's 784 MW of installed wind capacity, are 

contracted to a utility in northern Indiana. Contractor said the SD PUC believes REC ownership 

makes up less than 10 percent of in-state generation. Commenters said that the result of the 

incorrect baseline (EPA-calculated 24 percent versus the SD PUC-calculated less than 10 

percent) will be a state goal that is even more onerous than EPA suggests in its proposed rule. 

Commenters said that given the already high penetration of wind generation in the state, 

integrating additional intermittent wind resources will be more difficult than in states that have 

lower penetration. Commenters said if Building Block 3 is applied with the proper baseline, 

South Dakota's renewable target should be reduced in acknowledgement of the current export of 

RECs and the already high levels of wind penetration.

Commenters stated that REC tracking systems have been developed nationwide. Commenters

said in South Dakota, this includes the development of two tracking systems, the Midwest 

Renewable Energy Tracking System (MRETS) and the Western Renewable Energy Generation 

Information System (WREGIS). Commenters said that these two regional systems were built 

with volunteer hours from state and regulatory agencies, and funded by ratepayers across the 

West and Midwest. Commenters said that both systems employ inclusive stakeholder processes 

for the accommodation of policy needs and changes, such as this proposal. Commenters said the 

final rule should allow the use of established tracking system for compliance purposes.

Comment 280: SD - Questions about consistent inclusion/exclusionof generation/consumption 

in Indian Country when computing SD state goals

Response 280: For the EPA’s response to this comment, see sections VII and VIII of the final 

preamble and the CO2 Emission Performance Rate and Goal Computation TSD for CPP Final 

Rule supporting the final CPP. EPA does not include building block four in the final CPP 

quantification of BSER, which would appear to obviate the commenters concern here.

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

Commenters stated that EPA solicits comments on setting goals in Indian Country which contain 

affected electric generating units. Commenters said on page 4.5 of the Technical Support 

Document - GHG Abatement Measures, Energy Information Administration, EPA indicates 

state-level total generation was adjusted to remove utility-scale fossil generation located in 

Indian Country. Commenters said South Dakota is unable to determine if EPA excluded retail 

sales in Indian Country when determining South Dakota's energy efficiency goal. Commenters

said EPA does not address in any of the technical support documents how EPA proposes to 

handle renewable energy or energy efficiency in Indian Country, particularly with respect to 

Indian Country having no affected electric generating units. Commenters said EPA should give 

the state the flexibility to use renewable energy or energy efficiency that occurs in Indian 

Country. Commenters said if EPA will not, EPA should re-evaluate the state goals to eliminate 
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calculating renewable energy and energy efficiency goals that include electricity produced and 

sold in Indian Country.

Comment 281: SD - Comments stating that meeting HRI targets may impact a reliable, 

economic source of steam for other projects

Response 281: As described in the CO2 Emission Performance Rate and Goal Computation 

TSD for CPP Final Rule, the EPA is not making any unit-level requirements assumptions when 

implementing the building blocks. It is only make assumptions about what the regional fleet, in 

this case the eastern interconnect could achieve on average. There is no requirement or 

expectation that Big Stone make a specific heat rate improvement. See Section V.A.4.a for more 

discussion.

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

Commenters stated that since 2003 Big Stone Plant has provided a co-generation benefit to the 

nearby ethanol plant owned by Northern Lights Ethanol, LLC, providing the plant with a 

reliable, economic source of steam. Commenters stated that EPA and the State of South Dakota 

reviewed this project and Big Stone Plant's Title V permit was amended on August 8, 2001 

specifically for the purpose of authorizing this activity. Commenters stated that this cogeneration project has a 2% to 3% negative impact on Big Stone Plant's overall heat rate, but the 

steam is used for the critical purpose of producing biofuel with very low lifecycle GHG 

emissions. Commenters stated that if EPA were to proceed with requiring 6%, or even 4%, HRI 

at Big Stone Plant based on the baseline found in the proposed rule, then this economically and 

environmentally responsible co-generation of steam may be terminated. Commenters stated that 

by depriving states of authority to consider "other factors" in determining how to apply BSER to 

each designated unit within the state, EPA would cripple another of the Administration's own 

GHG reduction efforts: the effort to ramp-up production of low-GHG biofuels.

Commenters stated that EPA should reconsider the emission targets proposed for South Dakota. 

Commenters stated that because EPA has not comprehended the unique circumstances within the 

state, and because it has not allowed the state to consider unit-specific factors in determining 

what Big Stone Plant can achieve, EPA has overestimated what South Dakota can achieve. 

Commenters stated that much, if not all, of this problem could be avoided if EPA confined itself 

to the role expressly contemplated by Section 111(d) - determining BSER - and left to the states 

their statutorily-assigned task of establishing standards of performance applicable within their 

borders and applying those standards to individual units after consideration of statutorilyspecified factors such as the remaining useful life of each existing source.

Comment 282: SD - Improper baseline data; limited flexibility to use BB2

Response 282: See sections I.A. and VI of the final rule preamble of the CPP for the EPA’s

response to this comment. EPA deemed the Deer Creek Station to be "under construction" in 

2012, and adjusted South Dokata assigned incremental generation and emissions to South 

Dakota reflective of Deer Creek Station assumed capacity factor at 55% utilization.
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The following are summaries of the specific public comments under this comment:

Commenters stated that South Dakota's unique generation profile, including just one coal-tired 

steam electric generating unit (EGU) and a single natural gas combined-cycle plant (NGCC), 

severely constrains flexibility in meeting the state-level target. Commenters requested that EPA 

review the Plan's classification of the state's sole NGCC power plant as operational in 2012, even 

though it did not operate commercially until August of that year.

Commenters stated that nearly all of South Dakota's power sector carbon emissions are 

attributable to the state's only coal-fired steam EGU, the Big Stone Plant in northeastern South 

Dakota. Commenters said the facility is co-owned by Otter Tail Power Company, MontanaDakota Utilities Co., and NorthWestern Energy and is dispatched primarily by the Midcontinent 

Independent System Operator. Inc. (MISO). Commenters said the Big Stone Plant serves 

customers in Minnesota, North Dakota, South Dakota and Montana.

Commenters stated that the Big Stone Plant is in the midst of an approximately 400 million 

dollar environmental upgrade project to comply with the South Dakota regional haze state 

implementation plan approved by EPA in 2011. Commenters said that public utilities 

commissions in Minnesota and North Dakota granted advance prudence determinations for the 

project, after carefully weighing replacement generation alternatives. Commenters said that 

construction of the environmental upgrade project is now nearly 70 percent complete. 

Commenters said approximately 400 employees of the prime contractor and subcontractors arc 

working diligently to complete the project earlier than required and under budget.

Commenters stated that South Dakota also has only one NGCC EGU, the Deer Creek Station in 

eastern South Dakota. Commenters said the Deer Creek Station is owned by Basin Electric 

Power Cooperative and is presently dispatched by the Western-Integrated System. Commenters

said after the Western Area Power Administration, Basin and Heartland Consumers Power 

District have joined the Southwest Power Pool (SPP), as presently contemplated, Deer Creek 

Station will be dispatched by the SPP.

Commenters stated because Big Stone Plant and Deer Creek Station are South Dakota's only 

coal-fired steam and NGCC EGUs, a heavy reliance on the re-dispatch of electricity from coal to 

natural gas (Building Block 2) to achieve the state's required carbon reductions allows for little 

flexibility. Commenters said the Plan uses Deer Creek Station's actual 2012 capacity factor of a 

mere 1 percent in calculating South Dakota's required carbon emission rate reduction, even 

though Deer Creek Station did not become commercially operational until August of 2012. 

Commenters said these anomalies would require dispatch or Deer Creek Station at up to a 70 

percent capacity factor while essentially relegating Big Stone Plant, a baseload unit, to 

intermediate or even seasonal operation. Commenters said had EPA deemed the Deer Creek 

Station to be "under construction" in 2012, the Plan would have assigned Deer Creek Station an 

assumed capacity factor of 55 percent in 2012.

Commenters stated that electric consumers served by Otter Tail Power Company, MontanaDakota Utilities Co., and NorthWestern Energy should not have to absorb the costs or Big Stone 

Plant environmental upgrades to meet Clean Air Act regional haze requirements only to have 

access to a fraction of the energy the facility is capable of producing, at much higher costs per 
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unit or energy. Commenters said that Basin constructed the Deer Creek Station for its unique 

electric utility system requirements, not to meet consumer electric energy demand of neighboring 

electric utilities in an entirely different regional transmission organization.

Commenters urged EPA to consider revising the Plan to more accurately classify the Deer Creek 

Station as being under construction in 2012.

Comment 283: TN - The Proposed Carbon Rule leads to uneconomic and inefficient decisionmaking.

Response 283: For the EPA’s response to this comment, see the Regulatory Impact Analysis for 

the Clean Power Plan Final Rule, EPA-452/R-15-003 supporting the final CPP.

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

Commenters stated that the Proposed Carbon Rule is contrary to the Tennessee Valley Authority 

Act of 1933 (TVA Act), specifically the amendments to the TVA Act contained in the Energy 

Policy Act of 1992. Commenters said both the TVA Act and Energy Policy Act were acts of 

Congress passed by the legislative branch, yet with the Proposed Carbon Rule, the executive 

branch acting through EPA seeks to obviate the will of Congress by administrative fiat.

Commenters stated that the Proposed Carbon Rule ignores the purpose and history of the TVA 

Act. Commenters said this irreconcilable conflict is particularly acute when the sweeping scope 

of the rule is put against the Energy Policy Act amendment to the TVA Act. Commenters said 

the Energy Policy Act of 1992 amended the TVA Act and added the "Tennessee Valley 

Authority least-cost planning program." Commenters said under this statutory section, TVA 

"shall conduct a least-cost planning program" and "employ and implement a planning and 

selection process for new energy resources which evaluates the full range of existing and 

incremental resources ... in order to provide adequate and reliable service to electric customers of 

the Tennessee Valley Authority at the lowest system cost." Commenters said the least-cost 

planning mandate is also consistent with TVA's overall objectives under the TVA Act: "The 

Corporation shall charge rates for power ... having due regard for the primary objectives of the 

Act, including the objective that power shall be sold at rates as low as are feasible." 

Commenters stated that the Proposed Carbon Rule, in concert with other EPA overreach in 

recent years, has forced TVA to deviate from this least-cost planning mandate in contravention 

of the express language of the statute. Commenters said least-cost planning is a term of art in 

utility regulation, and provides the analytic goal for utilities in devising a resource portfolio. 

Commenters said the Proposed Carbon Rule creates an irreconcilable conflict between the intent 

of an 80-year-old statute that has been integral to the economic development and improvement of 

lives in the Tennessee Valley and an administrative rule that lawlessly seeks to impose a federal 

energy policy on the state of Tennessee. Commenters said this is a "federal energy policy" not 

passed by Congress.

Commenters stated that abandoning least-cost planning principles and policy has and will 

continue to lead to uneconomic and inefficient decision-making.
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Comment 284: TX - Disparate state goals would result in inequitable treatment of states, and 

rule penalizes early efforts made in TX; general BB concerns

Response 284: See sections I.A., VI VIII.B., and VIII.C. 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 said that disparate state goals proposed by EPA would result in inequitable 

treatment of the states as well as the affected individual EGUs, and Texas will be severely and 

disproportionately impacted by the rule. Commenters indicated that the rule penalizes states that 

have made early reductions.

Commenters said that states where the electrical generation is predominantly coal-based would 

be expected to make significantly less reductions under the proposal than states such as Texas 

that have a diversified portfolio of generation. Commenters indicated that under the proposed 

rule, some states would receive credit for renewable energy generation in the state goal 

calculation, yet Texas, which actually produces more non-hydro renewable energy than any other 

state, is being penalized by the EPA by assuming that Texas can produce even more renewable 

energy - without considering the costs and time necessary to do so. Commenters stated that 

Section 111(d) does not allow the EPA to establish emissions guidelines on a state-by-state basis 

in such a disparate and inequitable manner.

Commenters stated that the proposed rule will have a severe and disproportionate impact on 

Texas. Commenters stated that based on EPA's Integrated Planning Model (IPM) projections of 

state CO2 emissions from EGUs for the proposed rule, Texas would be required to make 

approximately 19% of all CO2 reductions necessary for the United States. Commenters said that 

Texas has more CO2 emissions from electric generation than any other state, and noted that 

Texas is the second most populous state in the United States, and has a large and diverse industry 

base. Commenters also noted that approximately 85 percent of Texas' electrical load is confined 

within a single region, and that region has limited interconnections to other transmission regions 

within Texas. 

Commenters stated that Texas has made significant efforts in developing a diversified and 

balanced energy generation mix, and is the nation's leader in wind generation. Commenters

stated that in 2012, Texas produced 23% of all wind energy produced in the United States, and 

more than twice as much wind energy as the next highest wind energy producing state. 

Commenters noted that the data the EPA used for this proposed rule demonstrates Texas' efforts 

in developing a diversified clean energy fleet while simultaneously meeting the tremendous 

energy needs of the state. Commenters said that the EPA is using these efforts to impose a more 

stringent standard on Texas than other states that are predominantly coal or have implemented 

little renewable energy.

Commenters had concerns about the building blocks and assumptions used in the calculation of 

the emission targets for Texas; for example "The improvements offered by Block 1 may be 

illusory" and "that within the ERCOT interconnection, there likely is little room for improvement 
308

in Block 1's heat rate improvement goal because much of the assumed efficiencies have already 

been implemented by coal-fired generation because of the competitive market". The commenters

also explained that "increasing the amount of renewable electricity may result in undesirable 

consequences such as the need to shutdown or ramp down much of the coal fired and nuclear 

fleet during certain times of the year, and those large nuclear generating units are not designed to 

ramp up and down quickly or easily."

Commenters stated that the assumed re-dispatch of power markets cannot be done to the scale 

proposed by EPA and that the difference between the actual 2012 coal generation and the EPA 

assumed generation is the equivalent of shutting down 11,000 MW of ERCOT coal plants or 

running coal plants only in the summer months. The commenters expressed concerns that the 

requirement for renewable energy targets for the South Central portion of the USA should be 

12% not 20%. 

Commenters stated EPA's expected emissions reductions for Texas, and resulting costs and 

economic impacts, are staggering. The commenters said Texas' 2012 CO2 emissions rate, as 

calculated for the purposes of the rulemaking, is 1,284 lbs/MWh-yr. The commenters said Texas 

has a lower emissions rate than 32 other states, far below the median state. The commenters said 

it is anticipated that Texas will have to reduce its overall CO2 emissions by 42% by 2030 under 

EPA's plan to meet the final emissions target of 791 lbs/MWh-yr. The commenters said this 

reduction far outpaces every other state in the country, with Texas shouldering roughly 18% of 

the entire country's CO2 reductions and nearly three times as much as the next state - Florida; 

this is despite having an emissions rate far less than the median state and produces only roughly 

11% of the country's electricity. The commenters said in fact, certain states are actually expected 

to increase their CO2 emissions, as a result of the rule; a significant component of these 

reductions will effectively have to be accomplished by the 2020 deadline.

Commenters were concerned with the extremely aggressive Texas 2020 and 2030 goals (853 lb 

CO2/MWh, 791 lb CO2/MWh, respectively) because (1) they are unachievable with respect to 

the existing fleet in Texas, and (2) even the newest, most efficient units, such as new NGCC, 

would not be able to meet these goals.

Commenters stated that NERA's analysis identified flaws and errors in EPA's "building block" 

assumptions and methodology that indicate that EPA's analysis does not support its 791 pounds 

CO2 per megawatt-hour target for Texas. Commenters stated that indeed, NERA's analysis 

shows that, at best, using EPA's own methodology, while correcting some but not necessarily all 

of EPA's errors, EPA's approach actually results in a Texas goal of approximately 940 pounds of 

CO2 per megawatt-hour. Commenters stated that their internal analysis confirms this and 

identifies other adjustments that show EPA's approach would, if applied without the errors that 

have been identified thus far, result in a Texas goal of well over 1,100 pounds CO2 per 

megawatt-hour. Commenters stated that hence, if Texas was forced to meet EPA's goal of 791 

pounds of CO2 per megawatt hour, the state would have to apply the building blocks even more 

aggressively than EPA falsely assumes, and the resulting economic impacts would be even more 

severe.
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Comment 285: CPP would require disproportionate reductions from TX and result in 

disproportionate impacts and severe economic costs.

Response 285: See section I.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 said the proposed regulation would cause both substantial disproportionate impacts 

on Texas and severe economic costs for Texas consumers, and these impacts have not been 

adequately considered in the EPA's analysis. Commenters said even though Texas has already 

made significant progress in developing a generation portfolio based on a diverse fuel mix, 

EPA's proposal would require more CO2 reductions from Texas than any other state and in 

amounts well out of proportion to its current share of CO2 emissions. Commenters said under 

EPA's assumptions used in developing the state goals, Texas is required to make 18% of the total 

U.S. CO2 reductions, yet it produces only 11% of CO2 emissions by EPA's own 2012 baseline. 

Commenters said by this same baseline, Texas is required to reduce CO2 emissions by 57.9 

million tons per year by 2030 - this is more than double the amount of the next closest state 

(Florida).

Commenters said further, EPA's modeling disproportionately penalizes Texas for proactively 

investing in a diverse generation portfolio, including efficient natural gas combined cycle units 

("NGCC") and renewables. Commenters said the EPA re-dispatch modeling from coal to 

NGCC's shows 72 million megawatt-hours of reduced output by the Texas coal fleet by 2020 

(versus a 2012 baseline) - this output reduction is 78% more than the next closest state (Florida). 

Commenters said a reduction of 72 million megawatt-hours amounts to 52% of Texas's 2012 

coal-fueled generation, representing 19% - nearly one fifth - of the entire nationwide reduction 

in coal generation that EPA requires (even though Texas generation accounts for just 11% of 

U.S. coal generation). Commenters said this is extremely disproportionate and overly 

burdensome as to Texas.

Commenters said EPA's proposal sets a standard for Texas that is clearly unreasonable and 

disproportionate compared to other states. Commenters said the Texas 2030 target of 791 pounds 

CO2 per megawatt-hour is 20% more stringent than the national average of 991 pounds CO2 per 

megawatt-hour and also well below EPA's proposed standard for new coal-fueled power plants 

of 1,100 pounds CO2 per megawatt-hour. Commenters said the EPA's targets vary widely among 

the states - from about 200 pounds CO2 per megawatt-hour to nearly 1,800 pounds CO2 per 

megawatt-hour. Commenters said thirty-one other states have final (2030) targets that are higher 

than Texas's on a pounds CO2 per megawatt-hour basis. Commenters said incredibly, thirteen 

states have final (2030) targets that are higher than Texas's 2012 baseline rate of 1,292 pounds 

CO2 per megawatt-hour.

Comment 286: Texas has been disproportionately targeted and will be disproportionately 

impacted, especially east Texas
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Response 286: See section I.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 said that Texas is a state that has been disproportionately targeted, and will be 

disparately impacted, by the Proposed Rule. 

EPA has taken a regionalized approach the building blocks and quantifying BSER in this final 

CPP which will address some of the commenters concerns about the impact of incremental 

NGCC generation being observed purely in state at proposal. 

Forced early retirements. Commenters said based upon the proposed EPA scenario, 

approximately 17,000 MW of total capacity is to be retired in Texas, of which 13,000 MW is 

coal capacity. The commenters said moreover, Texas already has a lower carbon emission rate 

than 30 other states, but is required to reduce more carbon tonnage than any other state and 

achieve proportionately greater reductions than many states with higher emission rates.

Emissions Reduction. Commenters said state-by-state standards vary widely in the Proposed 

Rule, with the EPA proposing that Texas should account for 18% to 25% of national CO2 

reduction (and that Texas reduce the overall production of carbon by its power plants by over 

40% in the next 18 years). The commenters said this is true even though Texas is one of the 

nation's fastest growing states and has one of the most robust and expanding economies to 

support. 

Commenters said Texas power plants account for only about 11 percent of the nation's carbon 

emissions, but those Texas facilities are expected by the EPA to make cuts that will amount to 

about 20 percent of the nation's total carbon reductions. The commenters said according to 

Kathleen Harnett White, former TCEQ chair and current director of the Texas Public Policy 

Foundation Armstrong Center for Energy & the Environment, "The (Clean Power Plan) would 

have a disproportionately large impact on Texas- more than any other state." The commenters

noted that "the regulatory mandate imposed on Texas is almost two times that of the next two 

states combined."

Credit for early reductions. Commenters said unfairly, the State of Texas gets zero credit under 

the Proposed Rule for the substantial improvements in renewable-energy resource usage 

(particularly with regard to adding wind power) made in the last decade. The commenters said 

ETEC and other Texas power generators have added biomass and hydro-electric facilities to their 

generation portfolios and wind power to their purchased power portfolios; but it is unclear 

whether those renewable facilities will receive any credit under the EPA's plan.

Costs and reliability impacts. Commenters said the Proposed Rule imposes on Texas unfair costs 

and illusory implementation alternatives. The commenters also said the scheme creates systemreliability challenges for Texas as a whole, and some even say that for Texas to comply with the 

rule would be physically impossible (at least within the timelines being proposed by the EPA). 

The commenters said this is especially true in east Texas, a unique part of the state from a 

power-planning and socioeconomic perspective, which (being largely outside of ERCOT and in 

the rural, heavily-wooded piney woods region) often suffers from greater reliability challenges 
311

than most other areas of Texas. The commenters said moreover, expert opinionssuggest that the 

overall structure of the Texas' energy-only electric market may not survive the rule's 

implementation in its current form.

Three RTOs. Commenters said adding complexity, administrative burden and cost for the State 

of Texas is the fact that Texas is the only state that has a physical presence within three electric 

interconnections, or regional transmission organizations (RTOs), including (i) the Electric 

Reliability Council of Texas power region (ERCOT) ; (ii) Southwest Power Pool (SPP); and (iii) 

Midcontinent Independent System Operator (MISO). The commenters said all of the Texas 

utilities (public or private) located in the eastern interconnection are members of SPP or MISO 

(as well as ERCOT in some cases). The commenters said attempting to comply with the EPA's 

rule will be extremely complex for Texas and will effectively cede to the EPA the authority 

currently held in Texas by the Texas legislature, the PUCT, ERCOT, and these other two RTOs 

operating in Texas. The commenters said from a practical perspective, the State of Texas will 

clearly face enormous complications in terms of trying to create a state implementation plan that 

adequately addresses all three RTOs that operate in Texas.

East Texas. Commenters said East Texas, which includes some of the poorest counties in the 

state, is perhaps most disparately impacted by the rule. The commenters said the East Texas 

Cooperatives are situated in all three RTOs (MISO, SPP and ERCOT). The commenters said the 

ETCs are primarily operating outside of ERCOT, and the ETCs have historically struggled to 

achieve adequate sources of generation and transmission in order to provide electric energy to 

their members. The commenters said ETEC (and the ETCs) in rural East Texas have attempted 

to diversify their generation alternatives, but are faced with limited renewable resources 

available in the region. The commenters said in East Texas, wind and solar opportunities are just 

not abundantly available. Commenters said while ETEC has recently invested in hydroelectric 

and biomass resources, the ETCs still rely on coal plants for about 63% of their wholesale power. 

The commenters said most of these coal plants have recently undertaken significant capital 

expenditures to improve their environmental controls in order to comply with EPA's Utility 

MATS and CSAPR (even before the rule was temporarily stayed); but many of these plants 

would be required to close under the EPA's proposed plan.

Commenters said due to historical concerns with lack of transmission infrastructure in East 

Texas, rural East Texans are generally just as concerned with reliability of electricity as with 

cost. The commenters said particularly disconcerting for ETEC, and its members in rural East 

Texas, is a recent Government Accountability Office ("GAO") report stating that even more 

coal-fired power plants will close because of environmental regulations and competition from 

other energy sources than previously thought. The commenters said the GAO report also 

indicates that these changes "may contribute to reliability challenges in some regions and these 

actions would likely increase electricity prices in some regions ... "; further, industry 

stakeholders and RTOs indicated to the GAO that they cannot reliably estimate the effects of the 

coal-plant retirements because of the complexities of the markets impacted by the Proposed 

Rule.

Local economic impacts. Commenters said finally, the practical effects of ETC-owned plants 

shutting down would be devastating to local communities in rural east Texas. The commenters
312

said each plant that is forced to shut down, or even has to curtail operations, would have harmful 

consequences on the small communities in East Texas that rely on revenue streams from such a 

plant to help fund local school systems and county governments. The commenters said further, 

the employment opportunities provided at the plants in which ETEC and its members have an 

ownership stake also provide necessary economic support in those communities, and each job 

that is lost will be felt. 

Comment 287: Texas is far and away the most significantly affected state, and the significant 

variation and seemingly random allocation of emission targets to different states are impacts that 

demand a far more detailed and reasoned explanation before the EPA proceeds any further.

Response 287: See section I.A. of the final rule preamble of the CPP for the EPA’s response to 

this comment.

EPA also suggest comparing relative burden among states using an absolute metric may not be 

the best metric to use for assessing disparate impacts. EPA also suggest that the percent 

reduction and percent change metrics be examined for the state goals for Texas in the final CPP.

EPA quantifies BSER using a regionalized approach based on the availability of the three 

identified building blocks.

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

Commenters said it must be recognized that Texas is singled out for special treatment under this 

proposed rule. The commenters said while Texas' required percentage reduction in GHG 

emissions is not as large as some states (42%), when applied to the actual magnitude of Texas' 

electric generation capacity the figures become very revealing of the real impact of the rule. The 

commenters said Texas is clearly the largest producer and consumer of power in the U.S, but that 

status is merely a reflection of Texas' position as a producer of fuel, manufactured goods and 

other products that meet the needs of the other states and our global trading partners. The 

commenters said under the Clean Power Plan, Texas is far and away the most significantly 

affected state:

By 2030, Texas must reduce coal-fired electric generation by over 72 million megawatt hours 

(MWH), Florida is a distant second at just over 40 million MWH.

Texas' required GHG reductions by 2030 are almost three times greater than those required of 

second place Florida and dwarf the requirements for any other state. 

To comply, Texas must reduce its coal-fired electric generation by over 53%; Indiana and 

Kentucky, the two closest states to Texas in terms of coal-fired generation, must reduce their 

generation from coal by 4.8% and 1%, respectively.

Texas leads the nation in the production of renewable energy. But by 2030, Texas must increase 

its use of renewable energy almost five times as much as the state closest to Texas in renewable 

energy capacity, California.
313

Commenters said the significant variation and seemingly random allocation of emission targets 

to the different states, and certainly the significantly greater impact of the rule on Texas, are 

clearly impacts that demand a far more detailed and reasoned explanation before this rule 

receives any further consideration by EPA.

Comment 288: States must receive credit for early emissions reductions; without it, Texas target 

cannot be achieved.

Response 288: See sections VI VIII.B., and VIII.C. 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 said CPS Energy supports and has made substantial investments already to 

implement the Building Blocks identified in the proposed rule, in order to reduce the company's 

carbon footprint. The commenters said given this strong and proactive commitment, CPS Energy 

is concerned that the Building Block assumptions used for computing the CO2 emission rate goal 

for Texas need to be revised to reflect reasonable performance levels for affected EGUs. The 

commenters said without adjustments, the state target is not achievable, even by those electric 

utilities, such as CPS Energy, who have undertaken proactive, voluntary efforts and will continue 

to significantly reduce their CO2 emissions. The commenters said CPS Energy is concerned that 

the proposed framework for the implementation of the Building Blocks will not allow any credit 

for CO2 emissions achieved by these early, voluntary actions during the period prior to the start 

of the regulatory program in 2020.

Commenters said in regards to early action credit, switching from coal generation to NGCC has 

been part of our overall generation strategy. The commenters said CPS Energy purchased an 

NGCC unit in 2012 in preparation for replacing the lost capacity of the Deely 1 and 2 coal units 

at the end of 2018. The commenters said, however, since CPS Energy purchased a NGCC unit 

(Rio Nogales) already in operation in 2012, the generation from Rio Nogales is already included 

in the 2012 data used for setting the state targets, so shutting down Deely has a diminished 

impact on the affected units' emission rate. The commenters said as mentioned, CPS Energy 

wants to ensure the rule allows for the state to give credit for this early action.

Comment 289: TX - Commenters indicated that review of the IPM files indicates errors were 

made in the EPA's assumptions.

Response 289: For the EPA’s response to this comment, see the CO2 Emission Performance 

Rate and Goal Computation TSD for CPP Final Rule supporting the final CPP. EPA did not 

consider CFP Power Plant an affected source at proposal or model in its 111(d) baseline for 

quantifying state goals. 

EPA’s power sector modeling is an illustrative model to capture system-wide impacts of a least 

cost compliance sceneario. The compliance model is not meant to replicate the building block 
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levels, but rather recognizes on the way reductions and changes in fuel market conditions that 

may leads EGUs and states towards compliance without replicating the levels observed in the 

individual building blocks. This is consistent with the compliance flexibilities discussed in 

section VIII. EPA does use power sector modeling when informing its assessment of building 

block two. See section V.D. and corresponding modeling for further details on this analysis.

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

Commenters said that the EPA's IPM files indicate that the CFB Power Plant in Calhoun County 

(ORIS Code 56708, IPM ID Numbers 56708_B_H1101 and 56708_B_H1201) would be subject 

to the rule and would even shut down as a result of the rule by 2020. However, commenters said, 

the CFB Power Plant should not be subject to the rule. Commenters said that based on the 

TCEQ's information, the CFB Power Plant is predominately a dedicated industrial power 

provider and while CFB Power Plant might have the capability of putting power to the electrical 

grid, the facility has not put sufficient power to the grid to trigger the applicability threshold the 

EPA used for the proposed rule. Commenters said that the EPA should not consider the CFB 

Power Plant as an applicable unit in the IPM files for this proposal.

Commenters stated that only announced shutdowns should be included in the IPM base case 

modeling. Commenters said that three of the coal-fired utility unit retirements in the 2018 IPM 

results for Texas have been announced by the companies, specifically Welsh Unit 2 and JT 

Deely Units 1 and 2. Commenters said however, as the TCEQ commented on the EPA's 2018 

emissions modeling platform, IPM also predicts that the San Miguel unit in Atascosa County 

will retire before 2018 even though the San Miguel Electric Cooperative has made no 

announcement of plans to retire their facility. Commenters stressed that only announced 

shutdowns should be included in the IPM base case modeling. Commenters said that a 

company's decision to retire an asset as substantial as a coal-fired utility unit is based on many 

factors the EPA is not privy to and that cannot be factored into IPM.

Comment 290: TX - Cannot achieve any meaningful improvement in efficiency at Spruce 2, a 

state-of-the-art facility.

Response 290: See section V.C. of the final rule preamble of the CPP for the EPA’s response to 

this comment and more information about Building Block 1.

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

Commenters said at Spruce 2, it is not possible to achieve any meaningful improvement in 

efficiency. Commenters said completed in 2009, Spruce 2 is a state of the art, high efficiency 

unit, and every effort was made during its design and construction to ensure that it was as 

efficient as possible. Commenters said the heat rate of this unit cannot be improved.

Comment 291: TX - BB1
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Response 291: See section V.C. of the final rule preamble of the CPP for the EPA’s response to 

this comment and more information about Building Block 1. EPA BSER quantification reflects 

the regional potential of the building blocks, and does not assume any particular unit will 

perform at the exact building block level.

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

Commenters stated EPA's prescribed heat rate improvement requirements are not technically 

achievable in Texas. The commenters said Texas is a deregulated competitive electricity market; 

without government subsidy or price setting, power plants are compelled to obtain the greatest 

level of efficiency possible, without triggering new source review ("NSR") permitting 

requirements. The commenters said Texas units have already implemented all best practices and 

equipment upgrades that are available; any megawatt of power that is not generated, but could be 

obtained through efficiency improvements, is a megawatt of unsold power and lost profit. The 

commenters added Texas' coal fleet is one of the youngest coal fleets in the country, meaning 

that the units are built to run more efficiently and do not have the heat rate improvement 

potential that older units may have. 

Commenters stated lignite units in Texas are faced with even additional complication and 

compliance difficulties. The commenters said as noted by EPA, "EGUs burning higher quality 

coals (e.g., bituminous) tend to be more efficient than EGUs burning lower quality coals with 

higher moisture contents (e.g., lignite). The commenters said bituminous coals have higher 

heating values of greater than 10,500 British thermal units per pound and lignite coals have 

higher heating values of less than 8,300 British thermal units per pound." The commenters said 

with a lower heat rate fuel, lignite units are compelled to be that much more efficient, and 

operators of these units will struggle that much more to extract more efficiencies from these 

EGUs. The commenters said many of Texas' lignite units also possess advanced environmental 

control technologies that have significant parasitic load; this parasitic load is typically greater

than on other non-lignite power plants, if for no other reason than the lower heat content in 

lignite will result in great auxiliary loads created by the need to treat larger volumes of flue gas 

when compared to higher BTU fuels. 

Commenters stated Texas generators have already achieved all of the efficiencies that are 

economically achievable at their units, making it "[in] feasible" for EPA "to prescribe or enforce 

a standard of performance;" therefore, if EPA intends to pursue future controls for coal-fired 

EGUs, the only viable means is through a work-practice standard. The commenters said workpractice standards have been components of EPA's recent rulemakings, including the MATS 

Rule. 

Comment 292: TX - BB2 - Texas is disproportionately impacted by the proposed rule; effect of 

2012 baseline; 70% CF, nameplate capacity

Response 292: See sections I.A., V.D., and VI 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:
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Texas disproportionately impacted. Commenters stated ignoring EPA's expected off-the-top 6% 

reduction to coal in Block 1 and looking solely at the reductions to coal-generation due to forced 

coal-to-NGCC switching, Texas must reduce its coal-fired generation of electricity by 52% 

under Block 2 of the BSER model. The commenters said this is over 72 million MWh-yr (from 

139 million MWh-yr to 67 million MWh-yr), far more than any other state; Florida is second 

with a 40 million MWh-yr reduction. The commenters said EPA itself predicts that by 2020, 

Texas will retire 13,072 MW of coal generation, in addition to nearly 3,500 MW of natural gas 

generation; other states may be required to retire as little as zero coal generation. 

Effect of 2012 baseline. Commenters stated by selecting 2012 as the baseline year, EPA has 

significantly understated the proposed reduction in the dispatching coal-fired plants that will 

occur because 2012 was a year in which coal generation ran less due to depressed natural gas 

prices. The commenters said Texas generated 149,404,244 MWh of coal-generated electricity in 

2013; over 10 MWh more than 2012, so the actual reduction in coalfired generation is much 

greater than predicted in the rule. The commenters said the majority of this reduction will have to 

occur by 2020 - less than four years after the rule is finalized. 

70% Capacity factor. Commenters said the EPA has not demonstrated that NGCC gas turbine 

plants in Texas can run reliably and continuously at the 70% capacity factor that EPA's building 

block 2 requires - certainly not on EPA's proposed timeline. Commenters said the EPA's analysis 

concluded that in recent years, due to "historic lows" in natural gas prices, "operators have 

shifted significant quantities of generation from coal units to NGCCs." Commenters said yet, 

EPA could identify very few NGCCs that operated at a capacity factor of 70% or higher, despite 

the favorable economic conditions.

Nameplate Capacity. Commenters said the EPA overstated the capacity of the existing NGCC 

units by using nameplate capacity rather than feasible capacity as reflected in EPA's modeling. 

Commenters said in Texas, EPA assumed 37.5 GW of existing NGCC capacity in calculating the 

CO2 rate target; however, EPA's own modeling database, NEEDS, indicates that only 34.8 GW 

of capacity would actually be available. Commenters said using nameplate capacity results in 

EPA adding an erroneously high level of gas-fired generation into a state's goal calculation, 

thereby excessively reducing the amount of coal-fueled generation included in determining a 

state's goal. Commenters said the summer net capacity, which for Texas is 32.8 GW, is the most 

appropriate measure to reflect actual available capacity. Commenters said when corrected for 

nameplate error, the capacity factors that would actually be required to reach these generation 

levels when applied to summer net capacities in Texas is 80.3%, not 70%. Commenters said the 

difference in generation adds to the excessive level of NGCC re-dispatch that EPA includes in 

building block 2.

Comment 293: TX - BB2 - natural gas generation and infrastructure limitations

Response 293: See section V.D. of the final rule preamble of the CPP for the EPA’s response to 

this comment and more information about Building Block 2.

The following are summaries of the specific public comments under this comment:
317

Commenters said the EPA says on the one hand that it "does not presume that states with limited 

natural gas generation or infrastructure will have to develop those resources," but then it 

concedes that "[u]pgrades to pipeline and transmission infrastructure" will be "potentially needed 

to meet additional use of existing facilities."Commenters said the EPA has not demonstrated that 

Texas can meet EPA's building block 2 target without further developing its natural gas 

generation or infrastructure and can meet those targets within EPA's stated timeline. 

Natural Gas Generation Capacity

Commenters said in 2012, the existing NGCC fleet for the state of Texas consumed 

approximately 1,111 bcf of natural gas, and in order for the existing NGCC fleet to increase in 

capacity factor from 45% to 70%, an increase of approximately 648 bcf over the 2012 

consumption would be required. Commenters said this increase of 58% in natural gas 

consumption for the existing NGCC fleet in Texas would result in a total of 1,759 bcf. 

Commenters said in addition to the existing NGCC resources, other existing natural gas-fired 

resources will have to provide energy (either simple cycle units or boilers). Commenters said the 

total existing natural gas-fired fleet under the proposed rule's assumptions may utilize over 2,100 

bcf. Commenters said to meet energy load requirements, new natural gas-fired resources will 

need to be constructed to provide electric generation above and beyond the assumptions outlined 

above for existing units. Commenters said new natural gas-fired resources could be expected to 

utilize an approximately 350 bcf on average no earlier than 2020 to 2030. Commenters said thus, 

new and existing units in Texas may require over 2,450 bcf/year of natural gas, which would 

represent about 35% of Texas's total natural gas production. 

Pipeline Capacity

Commenters said the necessary studies have not been conducted to determine whether Texas has 

the natural gas pipeline capacity to distribute the quantity of natural gas needed to meet EPA's 

building block 2 target for Texas within EPA's deadline. Commenters said the EPA's review of 

national averages and trends certainly does not make this demonstration. Commenters said as 

assumed within building block 2, the existing NGCC fleet must increase its generation over 

historical levels, thus requiring significantly more natural gas for fuel than historically utilized. 

Commenters said the EPA has assumed that existing NGCC plants will operate at a 70% 

capacity factor. Commenters said under that assumption, a 500 MW plant burning approximately 

100,000 MMBtu/day of natural gas would consume approximately 24 bcf of natural gas 

annually. Commenters said the natural gas usage of one baseload 500 MW NGCC plant 

operating in Texas will be nearly equivalent to, if not exceeding, the quantity of gas consumed 

by the residents of the city of Austin each a year (excluding the commercial and industrial 

sectors of Austin). Commenters said the state of Texas has 54 NGCC plants, only 3 of which 

operated with capacity factors of 70% or above in 2012. Commenters said both the existing 

interstate and intrastate natural gas pipeline systems have proven to be constrained during peak 

periods, and rules that force increased reliance on gas-fired generation will only exacerbate 

constraint conditions on the current system.
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Comment 294: TX - Individually, the Building Blocks appear to be workable, however, when 

implemented all at once in a complex power generation market the workability factor decreases, 

especially in meeting the 70% CF for NGCC

Response 294: See sections V.A., V.D., and V.E. of the final rule preamble of the CPP for the 

EPA’s response to this comment. Also, EPA takes a regionalized approach in this final CPP for 

quantifying BSER. Why it notes the building blocks for each region include, among other 

elemetns, the ability for NGCC to increase utilization to 75% level. Its regional approach to 

quantifying source-category rates means this potential is not always fully utilized. 

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

70% capacity factor difficult to achieve. Commenters said individually the Building Blocks 

appear to be workable, however, when implemented all at once in a complex power generation 

market, such as ERCOT, the workability factor decreases, especially in meeting the 70% 

capacity factor for NGCC. The commenters said the ERCOT region of Texas where CPS Energy 

is located has several distinguishing characteristics that impact the interaction of the Building 

Blocks. The commenters said ERCOT and CPS Energy have summer peaking systems, the 

ERCOT record summer peak is 68,305 MW and the winter peak is significantly lower at 57,265 

MW. The commenters said the region also has a high level of natural gas generation accounting 

for 40.5% of energy in 2013 and 56% of installed capacity in 2014. The commenters said the 

combination of these characteristics makes a 70% capacity factor for NGCC extremely difficult 

to achieve. The commenters said if an entity fails to achieve the objective in Building Block 2 

and tries to compensate with additional wind, solar, or Energy Efficiency and Demand Response 

(EE/DR), its actions will actually reduce the capacity factor of NGCCs by reducing the amount 

of time they will run. The commenters said therefore, the Building Blocks are not as flexible and 

as substitutable as envisioned in the rule.

Dynamics between wind resources and NGCC. Commenters said for example, wind generation 

is currently Texas' the primary Renewable Energy (RE) resource and is likely to be the main 

contributor to Building Block 3. The commenters said the 12,000 MW of wind capacity installed 

already is expected to grow to 18,000 MW over the next five years. The commenters said the 

energy from wind is offered into the market at the lowest price of any resource and is dispatched 

first. The commenters said maximum wind output comes in the winter and spring seasons in 

ERCOT; during the summer, wind output tends to be lower. The commenters said at all times 

and seasons, wind output varies significantly. The commenters said in ERCOT, as wind varies, 

gas units make up for the variance by increasing their output. The commenters said a wind 

integration study commissioned by ERCOT (and authored by GE) found that wind generation 

most significantly impacted the dispatch of NGCC units by forcing them to cycle off and on as 

wind ramped up and down. The commenters said experience validates the GE study; the 

modeling was particularly accurate during lower load seasons. The commenters said the result of 

the dynamics between wind resources and NGCC suggests that the 70% capacity factor cannot 

be achieved.

Dynamics of EE/DR and NGCC. Commenters said another example is in regards to how EE/DR 

can lower NGCC dispatch. The commenters said EE/DR programs attempt to permanently 

reduce or shift peak demand, and programs that shave or eliminate peak consumption exclusively 
319

are likely to reduce the need for peaking units. The commenters said customers benefit from 

lower bills and energy efficiency in the form of more efficient air conditioning systems or other 

measures that reduce demand. The commenters said demand reductions can lower the capacity 

factors for NGCC units because not as much output is needed from them. The commenters said 

given these dynamics, it is important for the rule to recognize that Texas already has a very high 

utilization of NGCC units that interact in the ERCOT market with significant renewable capacity 

and robust DR and EE programs.

Comment 295: TX - BB3 RE

Response 295: See section V.E. of the final rule preamble of the CPP for the EPA’s response to 

this comment and more information about Building Block 3 and the CO2 Emission Performance 

Rate and Goal Computation TSD for CPP Final Rule supporting the final CPP.

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

Texas can easily achieve RE target. Commenters stated in Texas, the RE target is calculated 

based on the South Central Region's renewable energy goal of 20 percent; according to EPA, 

Texas can feasibly increase its renewable energy capacity from 34,017 GWh in 2012, to 85,963 

GWh in 2030. 

Commenters stated although the proposed rule suggests that these estimates are not intended to 

represent the business-as-usual rate of renewable energy deployment, for many states, including 

Texas, EPA's arbitrary use of 2012 data as a baseline combined with its arbitrary cap on 

renewable deployment produces that very result. The commenters said by 2013, Texas had 

already met more than 10 percent of its electricity use with wind power and other renewable 

resources, and is therefore already exceeding EPA's renewable energy target for 2019. The 

commenters said this is due, in large part, to EPA's unsupported assumption that Texas's 2012 

renewable energy generation will remain stagnant through 2017, when state implementation 

plans are due and the CPP compliance period; from 2007 through 2013, Texas's overall 

renewable energy deployment has increased annually at a steady rate of approximately 1.1% of 

total generation. The commenters said in 2014, ERCOT anticipates that total renewable energy 

generation capacity will increase to 14.4% of total capacity, exceeding EPA's forecast for 

2023; ERCOT expects Texas to double its wind energy capacity between 2013 and 2017, to 

some 21,000 MWs, and this does not include wind projects being developed to serve the 

Southwestern Power Pool outside of ERCOT. 

Commenters stated at these rates - that is, under a "business-as-usual" approach and largely 

independent of the CPP - Texas will exceed EPA's renewable energy goal by 2022 - 8 years 

before the end compliance date. The commenters said ERCOT's long-term study assessment 

confirms that even without any significant new environmental regulations, the statewide trend in 

renewables will continue. The commenters said even assuming a "business as usual" scenario 

(i.e., without the CPP), ERCOT estimates that nearly 10,000 MW of solar will be added by 2029. 

The commenters said on the back of the compliance period, the EPA arbitrarily caps each state's 

forecasted renewable generation when it reaches what the EPA describes as the "maximum state 
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target." The commenters said thus, once Texas achieves the 20% goal, the state's renewable 

energy deployment is assumed to be flat for the remainder of the compliance period. The 

commenters said by arbitrarily assuming Texas's renewable energy deployment remains flat from 

2012 through 2017, and then capping the state's target when it reaches 20% in 2022, the CPP 

does nothing to actually drive renewable energy development in Texas, and instead acts to 

weaken the state's overall target. The commenters said this does not meet the best system of 

emission reduction standard, but rather represents the status quo without taking into account any 

of the technological and market dynamics that will likely drive further renewable energy 

development over and above current "business as usual" forecasts. 

Commenters urged the EPA to recalculate Texas's renewable energy goal in a manner that 

accurately accounts for the state's historical performance, and therefore drives future change. The 

commenters said renewable energy generation is growing very quickly; in 2012 alone, installed 

wind capacity increased by nearly 28% and installed solar PV grew by over 83%. The 

commenters said it is well-established that Texas has significantly greater potential for renewable 

energy than the CPP forecast. The commenters said in light of Texas's tremendous renewable 

energy growth, there is no basis in the record to assume zero growth in renewable energy 

between 2012 and 2017; similarly, there is no basis in the record to assume Texas will achieve 

no more than 20% renewable energy deployment, given that the state is on target to exceed that 

goal within the next 5-7 years.

Texas RPS must be considered. Commenters stated Texas has an RPS that was not considered by 

EPA nor included in the averaging for the South Central region; specifically, the Texas Utilities 

Code includes the following: 

(a) It is the intent of the legislature that by January 1, 2015, an additional 5,000 megawatts of 

generating capacity from renewable energy technologies will have been installed in this state; the 

cumulative installed renewable capacity in this state shall total 5,880 megawatts by January 1, 

2015, and the commission shall establish a target of 10,000 megawatts of installed renewable 

capacity by January 1, 2025. 

Commenters said including Texas' RPS into the regional average would reduce the average 

imposed on Texas and other states within the region; this is a significant oversight that directly 

impacts the interim and final emissions targets and undermines the renewable targets applied to 

every state within the South Central region. 

Texas has largest RE burden. Commenters said the EPA assumes massive and unprecedented 

increases in renewables in Texas on an unreasonable timeline. Commenters said the 2030 Texas 

renewables target is set at 20% (based solely on the EPA's interpretation of the Kansas 

Renewable Portfolio Standard ("RPS"), and Texas is deemed to have 2.3 terawatt-hours of "atrisk" nuclear. Commenters said this means that Texas would need to increase its share of 

renewable and "at-risk" nuclear generation from 7.9% in 2012 to 20.5% in 2030. Commenters

noted that the average target for the U.S. as a whole is much lower at 15.2% of 2012 total 

generation.

Commenters stated Kansas' model should not be a model for Texas or the rest of the South 

Central region; the electric market of Kansas is extremely different than Texas'; as an initial 
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matter, Kansas is much smaller than Texas without nearly the amount of electricity-intensive 

industry. The commenters said Texas' total electricity generation in 2012 was nearly ten times 

greater than Kansas' total electricity generation. The commenters said Texas' renewable 

generation was 34,016,697 MWh in 2012, while Kansas' was only 5,252,653 MWh. The 

commenters said in order for Texas to reach the renewable target, it will therefore have to install 

roughly 10 times the amount of renewable energy that Kansas will have to do under the Rule 

Proposal; this makes a 20% renewable target, practically, much easier for Kansas to meet over 

Texas.

Commenters stated no state has a greater burden under Block 3 than Texas; Texas has 

significantly more renewable generation than any other state. The commenters said the 

renewable generation component of Texas' generation mix took over four decades to develop 

into its current capacity; it was heavily subsidized by the federal government. The commenters

said EPA in this Rule Proposal assumes, without consideration of economics or grid stability, 

that renewable generation in Texas will increase by 153% (51,946,805 MWh) in just 8-14 years 

(from the current ~34 million MWh-yr to 86 million MWh-yr -- a difference of 52 million MWhyr). 

Commenters stated the assumed renewable electricity increase for Texas is far greater than any 

other state (almost twice as much as the second highest state - Pennsylvania). The commenters

said compared to the top ten current generators of renewable electricity, Texas' expected increase 

is dramatically higher than the 2nd highest generator of renewable electricity, California, which 

is assumed to increase by just 37%. The commenters said EPA even models decreases in 

renewable electricity production in Iowa and Minnesota, currently the 3rd and 4th highest 

generators of renewable electricity.

Solar Potential

Commenters asserted that the EPA significantly underestimated the amount of achievable and 

cost-effective solar energy generation in Texas; indeed, Texas has the highest solar potential in 

the nation and a study by the National Renewable Energy Lab demonstrated that Texas has the 

technical potential to generate more than 78,717 GWh/year from rooftop solar. The commenters

said although there is currently only 231 MW of installed solar generation capacity in Texas, 

there is over 5,800 MW of utility-scale solar generation in various stages of ERCOT's 

interconnection process. The commenters urged the EPA to incorporate this data into its 

renewable energy projections, and modify Texas's renewable energy goal to more accurately 

reflect the actual and expected deployment of solar. 

Commenters stated the EPA must correct its renewable energy goals to account for the potential 

for DG, which has shown exceptional growth in recent years. The commenters said unlike EPA's 

approach, the Union of Concerned Scientists' Demonstrated Growth approach rightly accounts 

for DG potential, and recognizes that the number of rooftop solar installations grew by an 

average of more than 50 percent per year between 2008 and 2013, nationally. The commenters

said while Texas's current level of installed DG is relatively small, it is growing at a tremendous 

rate, and recent changes allowing third-party leasing have heated up the market in areas like 

Dallas and Houston. 
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Comment 296: Texas's market-based renewable program will likely exceed the EPA's 20% 

energy goal. Rather than set a goal likely to be exceeded, the EPA should encourage a higher 

standard to maximize Texas renewable energy. Brief discussion of the status of various RE is 

provided

Response 296: See section V.E. of the final rule preamble of the CPP for the EPA’s response to 

this comment and more information about Building Block 3.

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

Renewables as a whole. Commenters said Texas's market-based renewable program will likely 

exceed the EPA's 20% energy goal. The commenters said Texas should submit a rate of progress 

report on these gains, and if the state fails to realize the goal by the mid-2020s, the EPA should 

commit to asking the Texas state legislature for action on this issue.

Commenters said as calculated by the Union of Concerned Scientists (UCS) in their comments 

on the Plan, Texas is likely to significantly exceed EPA's renewable energy goal simply by 

following a business-as-usual growth plan. The commenters said the UCS calculates that Texas, 

which is in the UCS's high renewable growth area, should be able to grow its renewable industry 

until it represents 27% of electrical sales, compared to the EPA projection of 17%. The 

commenters said rather than set a goal likely to be exceeded, the EPA should encourage a higher 

standard to maximize Texas's potential for increasing reliance on renewables and reducing 

carbon emissions.

Wind. Commenters offered the following points:

• 12,824 MW of wind power generates 11 % of Texas energy

• With 7,988 MW of additional wind resources expected to be built by the end of 

2016, wind will produce a total of 19,430 MW, or nearly 20% of the state's 

energy

• 25,500 MW in additional requests have been filed for interconnection of wind 

plants to the utility grid

By the end of this year, CO2 will already have been reduced by 7.9 MMT through use of 

renewables, and new wind power is expected to reduce CO2 by an additional 13 MMT by 2020.

Solar. Commenters said Texas has the nation's largest solar potential, which is just beginning to 

be developed and can be expanded very rapidly. Commenters said there are currently 5,811 

MWs of interconnections requested for utility-scale solar plants in ERCOT.

Energy storage. Commenters said energy storage projects, which use batteries and compressed 

air in underground salt domes to capture renewable energy and save it for later use, are being 

developed and permitted across the state. The commenters said if built, these facilities should 

eliminate the need for other gas peakers. The commenters said storage facilities should be 

counted in any analysis of Texas's ability to reduce carbon emissions.
323

Commenters said 640 MW of compressed-air energy storage has been permitted in Texas, and 

Oncor, the state's largest electric transmission and distribution service provider, is proposing a 

5,000 MW-storage project at distribution stations across the state, which would enable much of 

the state's excess renewable energy to be stored and redistributed later.

Publicly-announced energy storage. Commenters provided the following information:

Apex Corp. has announced 370 MW of CAES (compressed air energy storage) in East Texas and 

Dresser-Rand Group Inc. has announced that Apex has ordered the equipment and posted the 

financial security to back up the order.

Chamisa Energy has announced that it will build 270 MW of CAES in the Texas Panhandle.

Duke Energy has already built 36 MW of lead-acid battery storage, now online in Notrees, 

Texas.

All of those publicly announced projects will generate a total of 640 MW by summer 2016.

Texas grid operator ERCOT's last System Planning Report shows that 874 MW of storage is 

undergoing a full interconnection study, indicating that it is likely to be built.

By 2018, 300-500 MW (mostly Li) more energy storage will be added as UPS systems on 

customer premises behind the meter.

By 2020, Texas is expected to have a total of up to 1GW-1.5 GW of storage online.

Geothermal. Commenters said Texas has vast untapped geothermal resources located near the 

oldest and most-polluting coal plants and which should be counted in the EPA's analysis of 

Texas's renewable potential.

Interconnections. Commenters said two large solid state direct current interconnections -

expected to be built in the next three years in the Panhandle and East Texas - will be able to 

transfer 3,000-5,000 MW of energy, most of it renewable energy, to other parts of the country.

Comment 297: TX - BB4 - not clear if goals are realistic; scope of goals may have to change; 

effect of deregulated competitive market and regulatory structure; forced power rationing may be 

required

Response 297: See section V.A. of the final rule preamble of the CPP for the EPA’s response to 

this comment and more information about Building Block 4.

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

Commenters stated that the building block 4 goals contained in the rule would require Texas to 

institute new, more aggressive energy efficiency requirements, and it's not clear that reaching the 

goals in the proposed timeframe is realistic. The commenters said to reach the cumulative 
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energy efficiency savings proposed in Option 1, the Joint Utilities predict they will have to ramp 

up energy savings to approximately 6,700,000 MWh per year. The commenters said energy 

efficiency savings would most likely not be able to significantly ramp up until 2020; this could 

create a situation where the annual savings rate would have to increase at a far more aggressive 

rate than the already aggressive annual rate included in the proposed rule.

Commenters stated the scope of the utilities' energy efficiency goals will likely need to change as 

well; Texas's statute provides for an energy efficiency goal based on demand savings; in order to 

decrease CO2 emissions by increasing energy savings at the rate suggested in Rule 111(d), both 

the statute and the rule may need to be amended to include demand savings outside of summer or 

winter peak demand. The commenters said the utilities' current energy savings goal that requires 

utilities to meet an energy goal calculated from its demand savings goal using a 20 percent 

conservation load factor will not be sufficient to meet EPA's target for energy efficiency 

improvements. The commenters said furthermore, even if the PUCT [Public Utility Commission 

of Texas] increased the conservation load factor to 100 percent of the current demand savings 

goal, it would still not be sufficient to meet the target set by Rule 111(d).

Commenters stated energy efficiency measures and demand reductions have historically been 

achieved through voluntary programs; this typically involves the state or other entity creating an 

incentive program allowing end users to opt-in. The commenters said EPA's Rule Proposal 

contemplates that certain rigid targets are met every year in order to reach an ultimate target 

efficiency level; for example, EPA projects that Texas electricity use will be 9.91% lower in 

2029 than if the Rule Proposal were not adopted; however, EPA does not account for regional 

variations between the states including differences in: demographics, economic growth, 

regulatory structures, load growth, and other key factors. 

Commenters stated there are many unique obstacles impacting each state's ability to comply with 

EPA's proposed efficiency targets. The commenters said one of the key obstacles to achieving 

these reductions in Texas is its unique deregulated competitive market and regulatory 

structure; Texas is not a vertically integrated state, and EPA's reliance on vertically integrated 

states to establish energy efficiency targets to be applied to states with deregulated electricity 

markets is misguided. The commenters said ERCOT has found that EPA's "cumulative 9.91% 

savings from energy efficiency by 2029... is not consistent with current trends in energy 

efficiency in Texas;" further, Texas is an industrial state with many high demanding users of 

electricity. The commenters said these users may not be able to meet requisite increases in 

demand-side efficiency due to numerous production purposes; but yet, EPA maintains that Texas 

can meet these incredible Block 4 requirements. 

Commenters stated EPA also does not allow for any variations or modifications in instances 

where these targets cannot be met through voluntary or incentivized actions; in a recessionary 

market, end-users may not be inclined, regardless of incentive, to undertake investments that 

would reduce their demand. The commenters said despite this change in economics, the targets 

under EPA's Rule Proposal would remain the same. The commenters said in order to guarantee 

that the Rule Proposal's target reductions are met, it would likely require forced power rationing 

regardless of external factors; this is a power that few, if any, states possess or would desire to 

impose. The commenters said Texas is one of these states that has neither the power nor desire to 

mandate reduced electricity demand; it is also certainly not a power that EPA possesses. 
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Comment 298: TX - BB4 - increase existing state agency efficiency goals; track CO2 

reductions; create an efficiency market

Response 298: See section V.A. of the final rule preamble of the CPP for the EPA’s response to 

this comment and more information about Building Block 4.

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

Increase state agencies' efficiency goals. Commenters said the Texas Emissions Reduction plan 

requested that each state agency save 5% of the energy they consume per year. The commenters

said however, most agencies don't report their progress, and there is no penalty for failure. The 

commenters said since this program requires that state agencies save money, it is plausible that 

the Texas legislature could be convinced to put teeth into the requirements. The commenters said 

savings from the state agencies' 5% energy reduction program were 909,903 MWh/year, which, 

in turn, is reducing CO2 emissions by 435.000 tons per year.

Track CO2 reductions. Commenters said Texas A&M University's Energy Systems Lab has 

been designated to keep track of NOx reductions under Texas's SIP and certified by the EPA as 

the agency responsible for that activity. The commenters said the Energy Systems Lab should 

likewise be responsible for tracking CO2 emissions reductions and offsets under whatever state 

or federal carbon reduction plan is implemented.

Create an efficiency market. Commenters said Texas's 1999 Electrical Deregulation Act 

separated the old integrated utilities into three parts - retailers, generators, and transmission and 

distribution companies (TDU's). The commenters said the law prohibits generators from funding 

energy-efficiency programs operated by the transmission and distribution companies. The 

commenters said however, there may be a way to set up an energy-efficiency market within 

ERCOT that allows generators that can't meet the carbon goals to bid for efficiency and thus 

fund efficiency programs at TDU's.

Commenters recommended that ERCOT run this program outside the state's utility managed 

Energy Efficiency Resource Standard (EERS) program. The commenters said this would allow 

additional clarity and independence. The commenters said it would also help avoid the 

disincentive that occurs as a result of having the regulated TDU - whose revenue is based on the 

volumetric charges of energy that they carry on their system - operate a program that further 

reduces energy sales. Revenue for these programs could come out of offset payments made by 

generators or carbon fees charged to the generators.

Comment 299: TX - BB4 - Texas can easily meet the EPA target of 10% of peak energy, but EE 

programs are not popular with Texas regulators or legislators because they cut into natural gas 

and coal sales - in current political climate may be almost impossible to increase EE goal. The

EPA significantly overestimated the costs of EE programs. The EPA should require something of 

industrial class re EE, and should credit municipalities for EE reductions

Response 299: See section V.A. of the final rule preamble of the CPP for the EPA’s response to 

this comment and more information about Building Block 4.
326

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

Significant potential for use of energy efficiency. Commenters said Texas has tremendous 

potential for use of energy efficiency and reduction of carbon emissions and costs. The 

commenters said the state can easily meet EPA's target of saving 10% of the peak energy, or 

about 1.5% per year of peak demand, by 2030. The commenters said, however, efficiency 

programs are not popular with Texas regulators or legislators because they cut into natural gas 

and coal sales. The commenters indicated that in the current political climate, it may be almost 

impossible to increase the state's energy-efficiency goal from 0.4 % to 1.5% of peak demand per 

year, or 10% of peak energy per year. The commenters said the current Public Utility 

Commission (PUC) and the legislature have been resistant to increasing energy-efficiency goals, 

and that dynamic is expected to continue under the new governor. The commenters said, 

however, there are several ways to meet the 1.5 % target.

Commenters said savings from the PUC's 2013 program, currently at 0.4% of peak were 

2,205,082 MWh/year or 1.115 MMT of CO2. The commenters said however, Texas can and 

should do more. The commenters said the following studies demonstrate Texas has enormous but 

untapped energy-efficiency potential:

"Meeting Aggressive New State Goals for Utility-Sector Energy Efficiency: 

Examining Key Factors Associated With High Savings," by the American 

Council for an Energy Efficient Economy (ACEEE) in 2009.

"Assessment of the Feasible and Achievable Levels of Electricity Savings from 

Investor Owned Utilities in Texas: 2009-2018," by Itron (Itron Inc. is a 

technology and services company dedicated to the resourceful use of energy and 

water.) in 2009.

"A Profile of Energy-Efficiency Opportunities in Texas, appendix G of the Duke 

University-Georgia Tech study of Energy Efficiency in the South."

"The Benefits of Energy Efficiency in Texas" by ACEEE in 2011, "Energy 

Efficiency Investments as an Economic Productivity Strategy for Texas" by 

ACEEE March 2011. 

"Energy Efficiency and Demand Response- A Survey of Expert Opinion," by the 

Brattle Group 2011.

Commenters said these studies show that by 2020, the potential savings could reach 15,309 MW 

(Itron) and result in savings of $330 for a household, $31,000 for a commercial customer and 

$404,000 for an industrial customer. The commenters said further, they demonstrate that by 

2030, an aggressive program can reduce overall electricity consumption by 12% to 19% below 

2010 levels, saving businesses and households a cumulative $14 billion on utility bills, and 

creating 47,000 local jobs per year. The commenters said if implemented, the recommendations 

in these studies could reduce costly energy at peak demand and reduce as much as 30 MMT of 

CO2 by 2030.
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Commenters said in their comments on the EPA Plan, the ACEEE performed an extensive stateby-state analysis, which found that Texas could reach a cost-effective, 25% reduction in overall 

energy consumption through energy efficiency programs. The commenters said compared to 

2012 standards, the 25% reduction would result in no net increase in cost to consumers and 

achieve significant savings for consumers. The commenters said pointing out that energy 

efficiency is not given the same weight as natural gas generation in the proposed Plan, the 

ACEEE said: "A rule that sets a weak standard or does not clear the path for efficiency would 

leave states with more expensive compliance options" - and that "not only should a rulemaking 

that limits greenhouse gas emissions recognize the emissions benefits of energy efficiency, but it 

should also be stringent enough to overcome existing market barriers."

EPA overestimated cost of EE programs. Commenters said the EPA's proposed Plan 

significantly overestimates the cost of energy efficiency programs. The commenters said the 

EPA estimates the cost to be 6.5 to 9.1 cents per KWH when the real cost in Texas is 2 to 3.5 

cents, according to the PUC. 

Additional recommendations. Commenters said what the Plan should do is require states to 

achieve all energy efficiency that is cost effective. The commenters said in addition, an 

adjustment for the losses incurred during transmission and distribution of energy should be 

factored in to give a true measure of cost effectiveness and CO2 reduction. 

Industrial class EE. Commenters said in Texas the industrial class has opted out of the state 

efficiency program. The commenters said they claim that in an effort to improve business 

practices they have already achieved all the cost-effective energy efficiency that they can 

achieve. The commenters said at the very least, industries should be required to report and 

document investment and savings according to a state or national standard. The commenters

suggested another possibility would be to set them up as a separate class and use a "self-directed 

program" to encourage and maximize the consumption savings.

Credit for municipal EE programs. Commenters said some municipalities that own their 

electricity generation have moved forward aggressively with energy-efficiency programs, and 

they are on track to save over 1,500 MW of generation capacity by 2020. The commenters said 

the EPA Plan should include some method for counting these gains and giving them credit for 

them. The commenters said at the moment, these early adopters are penalized because they're not 

given credit for the billions they've put into aggressive energy-efficiency programs. The 

commenters said the EPA Plan should include evaluation, measurement and validation 

guidelines to insure that these programs are credited with the long-term saving they provide. The 

commenters said annual tracking of achievements should be conducted by an independent 

agency. The commenters said for example, the Energy Systems Lab at Texas A&M already 

performs similar duties and could expand its program to include robust reporting and tracking of 

the state's carbon-reduction programs.

Comment 300: TX - The EPA's IPM modeling parameters do not always match assumptions 

used in developing goals, and modeling identifies flaws with building block methodology
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Response 300: EPA compliance modeling is not meant to replicate the building block levels, but 

rather demonstrate an illustrative system-wide results of a least cost compliance pathway taking 

into account future infrastructure and market conditions affecting the power sector. Therefore, 

the source-category rates quantified based on building block one will not necessarily result in a 

building block one abatement technology being used to comply with that rate in the model or in 

the actual state plans.

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

Commenters said the results of EPA's modeling show as to Texas (to the extent they can be 

relied on at all) is that the EPA's building block methodology is deeply flawed and does not 

reflect EPA's modeled conditions.

Heat Rate Improvement. Commenters said the IPM reveals the unrealistic nature of EPA's 6% 

proposed heat rate improvement. The commenters said for example, EPA's 2025 model run has 

each coal-fueled EGU remaining in service modeled as if it has achieved a 6% heat rate 

improvement over the base case. The commenters said but, since units that IPM has not retired 

by 2025 would only generate 51 terawatt-hours in 2030 under EPA's goals (compared to 67 

terawatt-hours used in the Texas goal setting computations), those remaining units would not be 

operating at peak efficiency making the assumption of any heat rate improvement improbable, 

much less the modeled 6%. The commenters said this poor assumption of heat rate improvement 

is just the beginning of where the model fails to adequately simulate how the electricity sector 

would function under EPA's proposal.

Change in NGCC generation. Commenters said for example, EPA's building block 2 accounts 

for more than one-half of the Texas CO2 rate reductions in EPA's goal calculation. The 

commenters said as shown in Appendix G, under building block 2, EPA bases its Texas goal on 

an increase in existing NGCC generation from 148 million megawatt-hours in 2012 to 231 

million megawatt-hours in 2030. The commenters said EPA's IPM modeling, however, shows 

existing NGCC generation decreasing in Texas to 131 million megawatt-hours in 2030. The 

commenters said in other words, EPA's own IPM modeling does not support the generation 

shifting EPA is mandating with its building block methodology.

NGCC Capacity Factor. Commenters said the IPM output also shows flaws in EPA's 

assumptions for NGCCs in building block 2. The commenters said in EPA's 2025 IPM 

compliance scenario, existing NGCC units do not all operate at a 70% capacity factor. The 

commenters said, in fact, of the 221 units, only 71 have capacity factors over 70% and most of 

those have capacity factors between 80% and 87%. The commenters said eighty-four of the units 

have capacity factors less than 20%.

Change in renewable energy generation. Commenters said under building block 3, as shown in 

Appendix G, EPA bases its Texas goal on an increase in renewable generation from 34 million 

megawatt-hours in 2012 to 86 million megawatt-hours in 2030. Commenters said however, 

EPA's IPM modeling shows renewable generation only increasing in Texas to 45 million 

megawatt-hours in 2030, nowhere near the goal set by EPA. Commenters said thus, while EPA's 

IPM modeling increases renewable generation, it only increases it by 33%, not by 153% as EPA 

assumes in its goal setting.
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Energy efficiency assumptions. Commenters said the EPA manipulates the building block 4 

inputs to IPM "exogenously" - i.e., external to the model. The commenters said thus, instead of a 

demand side decrease of 38,158,249 net MWh from 2012 to 2030 used to calculate the State 

Goal for Texas, EPA's IPM modeling uses a decrease of 57,590,239 MWh - a substantial 

difference and much more aggressive and completely unfounded goal. The commenters said the 

EPA claims it applied energy efficiency measures "consistently" between its goal setting and its 

IPM modeling. The commenters said but there is a vast difference, in terms of economic and 

social impacts, between meeting electricity demand by shifting to another form of generation 

(blocks 2 and 3) and simply reducing generation (block 4). The commenters said taken at face 

value, what EPA's IPM modeling shows is that EPA's aggressive state goals will not result in a 

the emergence of "clean" generation, as EPA claims, but will simply mandate a reduction in the 

generation of electricity and thus economic growth. The commenters said in effect, then, EPA 

has not demonstrated that its own state goals can be met in any reasonable compliance scenario.

Electricity Prices. Commenters said the EPA's IPM modeling also predicts substantially higher 

electricity prices for Texas consumers. The commenters said the EPA's files show the wholesale 

price of electricity in Texas for 2030 is predicted to be just over $57 per megawatt-hour. The 

commenters said using sales of about 327 terawatt-hours predicted for 2030, wholesale cost 

alone would be almost $19 billion. The commenters said according to the Energy Information 

Administration, the average wholesale price in 2012 for the ERCOT Houston Zone was just 

under $36. The commenters said that is, EPA's $57 per megawatt-hour projection for 2030 

would be a more than 60% increase in wholesale prices relative to 2012. The commenters said 

with about 365 terawatt hours of sales, the cost would have been just over $13 billion. The 

commenters said that is an added cost of over $5 billion for less generation before even adding 

the cost of new transmission lines to bring in more wind to the load centers as EPA would 

mandate.

Other Flaws. Commenters said the IPM output shows other fundamental flaws in EPA's goal 

setting methodology. In the "parsed" files for 2025 that EPA made available, there are 45 coalfueled units (including three petroleum coke-fired units) in Texas, of which two are retired in the 

base case and 27 are retired in the Option 1 State Case. The commenters said of the 18 units that 

remain in the Option 1 State Case, only two coal-fueled units are operating in the SPP in 2015, 

Tolk Unit 1 and Tolk Unit 2, but at a 9.1% capacity factor. The commenters said even in a 

regulated reliability region, this low level of operation cannot be sustained. The commenters said 

in the competitive ERCOT region, three units are operated at less than a 30% capacity factor, and 

two of them, J.K. Spruce Unit 2 and Sandy Creek 2, are two of the newest, most efficient units in 

Texas. The commenters said the "compliance scenario" EPA modeled thus shows the distortions 

and unreasonable assumptions built into its goal-setting methodology.

Conclusion. Commenters said thus, far from validating EPA's methodology or demonstrating its 

reasonableness, EPA's own IPM modeling (to the extent it can be relied on at all) shows that its 

state goals are unrealistic and based on flawed assumptions. The commenters said certainly, 

EPA's modeling does not demonstrate the validity of EPA's building block methodology. The 

commenters said the EPA should heed the warning of its own modeling and withdraw its 

unreasonable proposal.
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Comment 301: TX - strengthen goals

Response 301: For the EPA’s response to this comment, see the CO2 Emission Performance 

Rate and Goal Computation TSD for CPP Final Rule supporting the final CPP.

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

Commenters stated Texas not only leads the country in the production of oil and natural gas and 

the overall consumption of electricity, but it is also leads the country in the emission of 

CO2; indeed, in 2011, Texas produced more carbon dioxide from industrial facilities, including 

power plants, than any state in the Union, and more than the next two states combined. The 

commenters said although there are 121 power plants in Texas, nearly 40% of the state's total 

carbon emissions from the electric sector come from just ten plants - all of which are 

approaching the end of their useful lifespan. The commenters said given Texas's role as the 

nation's single largest source of carbon pollution emissions from electric generating facilities and 

the fact that many Texas facilities are already nearing the end of their useful life, the 

commenters asserted the CPP can and should be strengthened, so as to drive the permanent 

retirement of these facilities within the next 15 years. The commenters said by prioritizing and 

more accurately accounting for recent and expected renewable energy development and energy 

efficiency in Texas, the CPP could more effectively drive the kinds of carbon emission 

reductions that will have a meaningful impact on the spiraling costs of global warming -

retirement of coal-burning generation. 

Commenters stated Texas has the technical ability and experience to be a leader in clean energy 

solutions: 

• Texas is already a leader among the states in passing legislation that promotes 

clean energy development; renewable energy is now a key component of Texas's 

energy mix, with wind energy alone providing approximately 10% of the state's 

electricity supply. 

• Texas employs over 28,000 renewable energy workers; these jobs span a number 

of industries, from wind turbine maintenance to semiconductor manufacturing. 

• Job growth is expected to remain strong over the next decade; expanding wind 

and solar energy industries are projected to add 6,000 jobs in Texas per year 

through 2020. 

• Over 1,300 Texas companies employ nearly 100,000 workers in industries 

directly and indirectly related to renewable energy in 2013.

• EPA should recognize and account for these potential economic benefits in its 

final rule.

Commenters stated according to the EPA, the application of EPA's building block methodology 

to Texas's 2012 energy portfolio results in a need to reduce its carbon emissions rate (CO2 

lbs/MWh) from a 2012 emissions rate of 1,420 lbs/MWh to a 2030 emissions rate of 791 

lbs/MWh - a nearly 45% reduction. The commenters said using EPA's target puts Texas among 
331

the states with the largest emissions reduction goal, but an analysis of Texas's current and 

expected renewable energy, energy efficiency, and planned natural gas capacity makes clear that 

EPA's target emissions rate for Texas is unduly conservative. The commenters said Texas can 

and should be required to do more. 

Comment 302: UT - UT can do more with RE, and EPA should set more ambitious target for 

UT

Response 302: For the EPA’s response to this comment, see the CO2 Emission Performance 

Rate and Goal Computation TSD for CPP Final Rule supporting the final CPP.

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

Commenters stated in 2012, Utah got 76% of its electricity from coal; this is nearly double the 

national average 39%; it got only 2.3% from eligible renewables, which is less than half the 

national average of 4.9%; Utah's electric rates are 20% below the national average. 

Commenters stated even though it has invested relatively little in renewable energy, Utah has 

enormous unused potential for utility-scale solar power, as well as substantial potential for wind 

and geothermal power. The commenters said the Utah Geological Survey prepared a Utah 

Renewable Energy Zone assessment in 2009; it identifies 826 Gigawatts of utility-scale capacity, 

9.1 Gigawatts of utility-scale wind capacity, and 2.2 Gigawatts of utility-scale geothermal 

capacity; 1 Gigawatt is enough to light over 5 million homes. 

Commenters stated of particular significance is the UREZ assessment's finding that a high 

concentration of solar, wind, and geothermal resources comes together in three southwestern 

Utah counties (Iron, Beaver, and Millard). The commenters said their close proximity would 

make it feasible to construct shared transmission lines to Utah's heavily-populated Wasatch Front 

communities; Utah's exceedingly modest carbon emissions rate reduction target does not seem to 

recognize the relative ease with which Utah could shift investments from dirty to clean energy by 

the year 2030. 

Commenters stated Utah's exceedingly modest carbon emission-rate reduction target also does 

not seem to recognize how little Utah has done so far to adopt regulatory incentives to shift its 

electric power generation from dirty to clean sources. The commenters said Utah is nominally a 

member of the Western Climate Initiative-a regional organization of states whose purpose is to 

reduce the causes and mitigate the effects of climate change in the West; it recommends a 

diverse set of regulatory measures to achieve these goals, almost all of which must be 

implemented by the Utah state legislature. 

Commenters stated the Western Climate Initiative has a diverse list of recommended regulatory 

steps designed to encourage a shift from dirty to clean energy that the Utah legislature, so far, 

has refused to take. The commenters said Utah has no restrictions on greenhouse gas emissions 

on any timetable, no enforceable Renewal Energy Portfolio standard for electric power or for 

transportation fuel, no provision allowing utilities to combine heat and power service, no 

automobile fuel economy standards, and no energy efficiency standards for appliances. The 
332

commenters said the large potential for such regulatory programs to shift investment in power 

generation from dirty to clean sources, therefore, remains largely untapped. 

Commenters stated there are large potential reductions in carbon emissions if Utah were to catch 

up to its fellow members of the Western Climate Initiative. The commenters said the Southwest 

Energy Efficiency Project (SWEEP) has conducted a study that identifies end-user efficiency 

programs alone that could reduce Utah's electricity consumption by 1.4 Gigawatts (20%) by 

2020. The commenters said exploiting these opportunities would increase employment by 3,100 

jobs by 2020, and save 3.2 billion gallons of water a year. Over the period 2010-2030, it would 

save $1.7 billion. 

Commenters stated if it is economically and technically feasible for Utah to reduce its carbon 

emissions through end-user efficiency by 20%s by 2020, it would seem that by 2030 technology 

would have advanced enough to bring that level to 27%; in other words, it should allow Utah to 

reach its carbon emission-rate target without further investment in other alternatives to coaleither NGCC or renewables. The commenters said this suggests that the EPA should take more 

account of the large potential of end-user efficiencies to quickly reduce Utah's carbon emissions, 

and use it to set a more ambitious final emissions target for the state of Utah. 

Comment 303: UT - Errors; Affected Sources

Response 303: For the EPA’s response to this comment, see the CO2 Emission Performance 

Rate and Goal Computation TSD for CPP Final Rule supporting the final CPP. For the Final 

Rule, Lake Side 2 was categorized as under construction in the final CPP analysis.

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

Commenters stated Utah's rate-based target contains serious errors. The commenters said the 

Lake Side 2 natural gas power plant should not have been included as an existing unit in the 

state's building block two calculation because it was still under construction in 2012. The 

commenters said instead, Lake Side 2 should be classified as "under construction" in calculating 

Utah's carbon dioxide emissions target. The commenters said preliminary analysis suggests that 

correctly classifying the Lake Side 2 facility would change Utah's compliance target by 46 lbs 

CO2/MWh.

Commenters stated the capacity of the Lake Side 2 natural gas power plant should not have been 

included in the state's capacity factor calculation because it was still in construction in 2012. The 

commenters said in EPA's Goal Computation Technical Support Document, EPA defines "under 

construction" as "anything that came online in 2013 or that was under construction, site prep, or 

testing by January 8, 2014." The commenters said Lake Side 2 went on line in May 2014 and by 

EPA's own definition should have been classified as "under construction". The commenters said 

preliminary analysis suggests that correctly classifying the Lake Side 2 facility would change 

Utah's compliance target from 1,322 lbs/MWh to 1,368 lbs/MWH. The commenters requested 

EPA to reclassify Lake Side 2 as under construction for the purpose of calculating Utah 2030 

emission target.
333

Commenters stated in calculating Utah's goal EPA classified Lake Side 2 as operating in 

2012; this is an error on the part of EPA. The commenters said for purposes of calculating Utah's 

goal EPA should have defined Lakeside 2 as being "under construction". The commenters said in 

its Goal Computation Technical Support Document EPA defines "under construction" as 

"anything that came online in 2013 or that was under construction, site prep, or testing by 

January 8, 2014." The commenters said Lake Side 2 went on line May 2014 and by EPA's own 

definition should have been classified as "under construction". 

Commenters stated reclassifying Lake Side 2 as under construction reduces the amount of coal 

generation that can be redispatched to NGCC plants and increases Utah's goal to 1,368 

lbs/MWH, making it less stringent; a higher goal reduces Utah's compliance gap from 391 

lbs/MWH to 345 lbs/MWH. 

Commenters stated in calculating Utah's target for building block 2, EPA incorrectly lists the 

natural gas combined cycle unit Lake Side 2 as operational in 2012. The commenters said the 

plant achieved commercial operation in June of 2014 and was not operational in 2012. The 

commenters Utah interim and final goals should be recalculated reflecting the fact that Lake Side 

2 was an NGCC facility under construction during 2012.

Commenters stated Utah's baseline emission rate and target should be recalculated to correctly 

account for emissions from one of its largest EGUs for which its 2012 emissions were 

significantly lower than average. The commenters said by utilizing average emissions and 

generation data for this EGU from 2005 through 2009, Utah's corrected baseline rate would be 

1,926.75 lb of CO2/MWh rather than 1,873.69 lb of CO2/MWh, as listed in the proposal. The 

commenters said this correction results in a revised Utah 2030 goal of 1,348.73 lb of CO2/MWh. 

The commenters said Utah's ultimate and interim targets also need to be adjusted to account for 

the Lakeside NGCC plant, which was incorrectly included as being operational in 2012 while, in 

fact, this plant was under construction during the 2012 baseline year. The commenters said fixing 

this error results in Utah's target being increased by approximately 47 lb of CO2/MWh, resulting 

in a revised final emission rate target of approximately 1,395 lb of CO2/MWh. The commenters 

said since any change to a State's emission rate-based target correspondingly affects its massbased goal, these adjustments need to be accounted for in the State's mass-based goal.

Comment 304: UT - BB1 HRI

Response 304: See section V.C. of the final rule preamble of the CPP for the EPA’s response to 

this comment and more information about Building Block 1.

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

Commenters stated the EPA's application of a six percent improvement to Utah is not based on 

any specific analysis of potential heat-rate improvements at Utah coal plants. The commenters 

said Utah's coal plants have little, if any, room for significant additional improvements in 

efficiency. Commenters said consistent with a recent EPRI study, six percent efficiency 

improvements at Utah coal plants are not attainable; conducting their own unit-by-unit 

assessment of potential efficiency gains, Utah's plant operators concluded that potential 
334

improvements would be minimal at best. The commenters said preliminary modeling suggests 

that a heat rate improvement of 1 percent across the Utah coal fleet will result in an overall 

reduction of the state's carbon dioxide emission rate of only 15 lbs CO2/MWh, rather than the 

100 lbs CO2/MWh projected by EPA. The commenters added many heat-rate improvement 

measures are simply recovering efficiency lost due to degradation from the original operating 

condition. The commenters said according to Utah's plant operators, achieving additional heatrate improvements will be very costly and subject to the law of diminishing returns.

Commenters stated the proposed rule does not give credit for existing plant efficiencies. The 

commenters said this approach penalizes power plants that have already made significant 

investments in cleaner, more efficient processes and technologies. The commenters said Utah's 

coal-fired power plants are among the most efficient in the nation; Utah has the third best coal 

fleet in the country for emissions rate and should be rewarded for its investment in plant 

efficiencies. The commenters said even after making the efficiency improvements proposed in 

block one, (improvements that are not feasible), twenty nine states would still have higher 

emission rates than Utah does today. The commenters said this result is patently unfair, resulting 

in less efficient power plants receiving unfair preference over Utah's more efficient power plants. 

The commenters said the EPA's one-size fits all efficiency assumptions, and its assignment of 

different carbon reduction targets to each state will result in less efficient coal-fired power plants 

being preferred over Utah's more efficient coal-fired power plants. The commenters said along 

with the inherent unfairness of this approach, it is inconsistent with the EPA's stated goal of 

reducing overall greenhouse gas emissions.

Comment 305: UT - BB2 Re-dispatch

Response 305: See section V.D. of the final rule preamble of the CPP for the EPA’s response to 

this comment and more information about Building Block 2.

EPA’s 70% capacity factor, as described at proposal reflected its historical assessment of the 

amount of net generation expected as a percent of total nameplate capacity. It did not reflect the 

amount of gross generation expected as described by commenters. EPA has switched its 

building block two approach in this final rule to 75% capacity factor based off summertime 

dependable capacity.

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

Commenters stated EPA's target for increased natural gas generation actually reflects a 

calculation of "gross" generation because EPA developed its gas generation target based on 

applying a 70 percent capacity factor to the "nameplate" capacity of existing gas units. The 

commenters said "Nameplate" capacity refers to the total "gross" MW because it reflects the 

maximum amount of electricity that a unit's generator is designed to deliver, not the amount of 

electricity that could be sold to the grid; therefore, EPA's 70 percent capacity factor calculation 

actually reflects gross MWH, not net MWH, whereas EPA's calculation of 2012 coal-fired 

generation is based on "net" generation. 
335

Commenters stated EPA's goal calculations for Block 2 (re-dispatch) are based on an 

inconsistent analysis that compares gross MWH of gas generation and net MWH of coal 

generation; as a result, "net" coal MWH are redispatched in Building Block 2 to "gross" NGCC 

MWH. The commenters said the difference between net and gross generation is not insignificant 

- as EPA explains, "the difference between gross and net electricity is the amount of electricity

used at the plant to operate components such as pumps, fans, motors, and pollution control 

devices," which "may represent from 4 to 12 percent of gross generation at a coal-fired steam 

EGU." The commenters said in other words, EPA's unfair "re-dispatch" comparison of net gas 

generation to gross coal generation itself may account for as much twice the difference in total 

generation as EPA's entire building Block 1 assumption of six percent. 

Commenters stated EPA needs to be consistent in its treatment generation capacity from natural 

gas generation and coal generation in calculating its goal for Utah. The commenters asked EPA 

to recalculate its Building Block 2 assumptions for the "re-dispatch" of coal generation to natural 

gas generation using the summer net dependable capacity of all of the affected units. The 

commenters said in the case of Utah, the total nameplate rated capacity of the NGCC units relied 

upon by EPA in the building Block 2 calculation is 1,298 MW, whereas the total summer net 

capacity is only 1,227 MW, a six percent difference. The commenters said use of the summer net 

capacity in determining the state goal from Utah's 2030 goal would change from 1,322 lb/MWh 

to 1,348 lb/MWh. 

Comment 306: UT - Treatment of Renewable Energy Under the Multi-state Process (MSP)

Response 306: See section VIII.C. 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 language in EPA's proposed rule and NODA would allow states to count outof-state renewable energy as part of their compliance plans creates the opportunity for Utah to 

consider including renewable energy allocated to Utah ratepayers through the PacifiCorp multistate process (MSP) towards its 2030 compliance obligations. The commenters said the MSP 

process, adopted by 5 states Public Utility Commissions, could be considered an "enforceable 

measure" with respect to the generation of renewable under the jurisdiction of Utah. The

commenters said this scenario evaluates what impact including imported renewable resources 

through the MSP allocation process has on both Utah's goal and emission rate. 

Commenters stated PacifiCorp serves load in 6 States and since 2002 the benefits and cost 

PacifiCorp's system have been allocated based on the multistate process and assigned on the 

percentage of PacifiCorp's load served in each state; for example, between June 2014-June 2015 

Utah is projected to represent approximately 42.63 percent of PacifiCorp's load and will be 

allocated 42.63 percent of PacifiCorp's benefits and costs. The commenters said PacifiCorp has 

significant renewable energy on its system and it allocates the benefits and costs of its renewable 

energy based on the MSP allocation; for this scenario Energy Strategies has collected data for all 

of PacifiCorp's system-wide renewable energy and allocated it's generation to each state using 
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the MSP Allocation formula and compared how the state's 2030 goal and emissions rate would 

be impacted relative to the Base Case 2020-2030 scenario. The commenters said for purposes of 

this analysis, and to be consistent, it was assumed that MSP renewable energy would be included 

in both the 2030 goal and 2020-2030 emissions rate calculation. 

Commenters stated the difference between the renewable energy generated in Utah and the 

renewable energy allocated to Utah rate payers is significant. The commenters said Utah 

produced 1,099,724 MWH of renewable energy in 2012, while Utah's MSP allocation from 

PacifiCorp's system was 2,575,879 MWH. The commenters said changing from EPA's method to 

an MSP allocation method has the effect of decreasing Utah's 2030 "business as usual" emission 

rate from 1,713 lbs/MWH to 1,561 lbs/MWH. The commenters said re-calculating Utah's EPA 

2030 goal using the MSP allocation increases the stringency of Utah's 2030 goal from 1,322 

lbs/MWH to 1,220 lbs/MWH. The commenters said the effect of these two changes (that is, a 

higher emission rate, but a less stringent goal) on Utah's compliance obligation is a reduction of 

Utah's compliance gap by 50 lbs/MWH to 341 lbs/MWH. 

Comment 307: VT - Goals

Response 307: For the EPA’s response to this comment, see the CO2 Emission Performance 

Rate and Goal Computation TSD for CPP Final Rule supporting the final CPP. EPA notes that 

the potential new units contemplated by commenter would be covered under 111(b) emission 

guidelines, and not any 111(d) rulemaking which only applies to affected sources. Therefore, 

while not this particular rulemaking, there are emission limitations that would be applied to new 

units that otherwise meet the applicability critiera described in this rulemaking.

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

Commenters recommended that all states be held accountable for maintaining a clean energy 

portfolio. The commenters said as the CPP is currently written, Vermont is excluded from any 

form of carbon reduction goals. The commenters said the EPA has justified this exception 

contending that Vermont does not contain carbon-emitting power plants; even though this is true, 

excluding Vermont from the CPP will not hold them accountable to maintaining a carbon-free 

electricity grid. The commenters said as a result, Vermont will be able to introduce carbonemitting sources without being penalized; this is especially important as Vermont currently plans 

to shut down the Vermont Yankee nuclear power plant, which could conceivably be replaced 

with a carbon-emitting source without any repercussions. The commenters said it is crucial to 

include all states in any future carbon regulations to ensure that every state implements a 

responsible energy plan and that newly built nonrenewable energy sources are both regulated and 

energy efficient.

Comment 308: VA - Goal Opposition

Response 308: For the EPA’s response to this comment, see the CO2 Emission Performance 

Rate and Goal Computation TSD for CPP Final Rule supporting the final CPP.
337

As discussed in section V of the preamble, the 111(b) and 111(d) goal comparision is not a 

comparision of equal metrics. Moreover, EPA has modified its quantification of BSER in this 

final rulemaking to a regionalized approach from which uniform source-category rates are 

derived. These are then equally applied across state’s existing unit fleet to estimate the state 

goals. This has the impact of reducing the numeric disparity in state goals described by 

commenters. EPA does not believe the goals or source-category rates require any particular EGU 

to retire as suggested by commenters. Moroever, for those retirements already scheduled post 

2012 in Virginia, the state will be able to take advantage of those reductions when demonstrating 

compliance with its state goal.

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

Commenters stated EPA's 2012 data and calculation of the proposed State emissions 

rates indicate that Virginia would need to eliminate and replace approximately 9 million annual 

megawatt hours of coal-fired generation with new zero-carbon resources by 2020. 

Commenters stated EPA's modeling replaces the 2,851 MW of fossil-fuel generation it projects 

will retire in the Dominion transmission zone by 2020 with only 351 MW of intermittent onshore 

wind; it is not clear how EPA concludes (if indeed it has) that reliability could be maintained in 

the Dominion transmission zone given this significant net reduction in capacity that the model 

EPA relied on to develop its Proposed Regulation. The commenters said even without the 

Proposed Regulation, other factors, including the Mercury Air Toxics Standard and moderate 

natural gas prices, are causing a historic amount of fossil-fuel generation retirements across the 

country during the next two years. The commenters said requiring a second wave of substantial 

retirements before the country has ridden out the first is disquieting. The commenters said to 

conclude that the Dominion transmission zone can replace 2,851 MW of dispatchable, fossil-fuel 

generation with 351 MW of intermittent wind, at a time of unprecedented retirements throughout 

the country, reveals a troubling lack of consideration for, if not threat to, maintaining a reliable 

electrical system for Virginia businesses and residents. 

Commenters stated the amount of new, zero-carbon energy production that EPA's data indicates 

Virginia would require to meet the Mandatory Interim Goal by 2020 is daunting; Virginia would 

need to add the equivalent of approximately 1,140MW of nuclear generation at the 90% "average 

utilization rate for U.S. nuclear units" (which EPA indicates is "consistent with long-term 

average annual utilization rates observed across the nuclear fleet") in order to achieve the 

emission reductions inherent in EPA's calculation of Virginia's proposed emissions rate. The 

commenters said the construction of 1,140 MW of additional nuclear capacity by 2020 

is unrealistic for Virginia or anywhere else in the nation. The commenters said currently, one 

nuclear project is under consideration in Virginia, though its need and cost have not yet been 

submitted to or reviewed by the Virginia SCC, as required by Virginia law; this project remains 

in the early stages of development, with an array of regulatory approvals needing to be sought 

and received should the project move forward; in fact, this project has been under review by the 

federal Nuclear Regulatory Commission for more than a decade. 

Commenters stated with regard to wind or solar, even if the operational concerns associated with 

replacing dispatchable, fossil-fuel generation with the variable, intermittent, and nondispatchable 

production from these renewable resources could be managed, there is still zero probability that 
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wind and solar resources can be developed in the time and on the scale necessary to 

accommodate the zero-carbon generation levels needed to meet the Mandatory Interim Goal in 

2020. The commenters said using a 31% capacity factor that the Department of Energy ("DOE") 

indicates was the national average for wind turbines in 2012, Virginia would need to add 3,300 

MW of wind generation by 2020. The commenters said arbitrarily increasing the historic 31% 

capacity factor for wind, which DOE indicates has not improved since 2000, to 50% would still 

require Virginia to add 2,050 MW of wind generation by 2020. 

Commenters stated nor can solar, with capacity factors lower than wind generation, realistically 

bridge the resource gap that would be created in Virginia by the Proposed Regulation; assuming 

an ambitious 25% capacity factor for Virginia solar, the Commonwealth would need to add 

4,100 MW of solar generation by 2020. The commenters said a combination of solar and wind of 

the magnitude needed to meet the Mandatory Interim Goal (adding, for example, 1,650 MW of 

wind and 2,050 MW of solar in Virginia) would be no less daunting. 

Commenters stated under EPA's proposal, Virginia will be one of the hardest hit states, with a 

32% reduction in carbon intensity required by 2020. The commenters said attempting to achieve 

this reduction will require a significant re-engineering of electricity in Virginia, and a significant 

re-dispatching of coal to natural gas. The commenters said this is contrary to the 

Commonwealth's commitment to fuel diversity and does not reflect the fundamental importance 

of coal in achieving our state's goals of: (1) ensuring that the cost of energy for Virginia 

consumers remains highly competitive, (2) maximizing our available reserves, (3) expanding and 

attracting business, and (4) increasing the reliability of Virginia's existing energy infrastructure. 

Commenters stated while EPA touts "flexibility" for states, this is an illusory claim in Virginia, 

since the schedule is far too short to achieve the required reductions without dramatic "slash and 

crash" tactics. The commenters said in short, there is no way to achieve EPA's proposed target 

for Virginia without significantly reducing coal, a consequence that will have a devastating 

impact on Virginia's coal industry, the communities of southwest Virginia, their two major 

freight railroads, Virginia's ports, electricity consumers, and the countless businesses and citizens 

who derive their livelihoods from coal or keep their lights on and systems running with reliable, 

coal-fired electricity. 

Commenters stated state flexibility in achieving EPA's target reductions is further restricted by 

EPA improperly restricting a state's ability to consider the remaining useful life of individual 

existing sources when applying the 111 (d) guidelines. The commenters said certain coal plants 

likely would have to shut down, regardless of their efficiency or whether they are needed to 

assure system reliability, unless a state is able to employ the flexibility expressly granted under 

Section Ill (d) to regulate exiting sources on a case-by-case basis. The commenters said by 

depriving states of this needed flexibility, the CPP will result in significant stranded investments 

made at Virginia facilities to be responsive to other recent EPA mandates - e.g. , Virginia City 

Hybrid Energy Center, which was placed in service in 2012 at an initial capital cost of $1.8 

billion; Chesterfield Power Station scrubbers, which were placed in service in 2011 and 2008 at 

an initial capital cost of $275 million; and the Clover Power Station, which was constructed and 

placed in service in 1995 and 1996 at an initial capital cost of $1.2 billion with a planned service 

life of over 50 years.
339

Commenters stated EPA's proposed CO2 emission performance "goals" for Virginia are 

unrealistic, arbitrary, capricious and unlawful. The commenters said it is important for EPA to 

realize that generators of electricity in the Commonwealth of Virginia have made great progress 

in reducing GHG emissions since 2005 while providing for greater flexibility and reliability in 

energy production. The commenters said according to the Virginia Department of Environmental 

Quality ("VDEQ"), emission reductions through 2012 of 39 percent have been achieved; these 

significant improvements have been made through natural market forces and voluntary actions. 

In light of this progress, the commenters urged EPA to reconsider the mandates in its proposed 

Section 111 (d) guidelines and look for solutions that will promote future progress. 

Commenters stated in Table 1 of EPA's proposed rule, the agency sets interim and final "ratebased CO2 emission performance goals" of 884 and 810 pounds of CO2 per MWh of net energy 

output for existing EGUs in Virginia subject to the rule. The commenters asserted these goals are 

completely unrealistic. The commenters noted that EPA's rate-based CO2 emission standard for 

new and modified EGUs is between 1,000 and 1,100 pounds of CO2 per MWh; in other words, 

the CO2 emission goal for existing EGUs in Virginia is more stringent than the CO2 emission 

standard for new EGUs. The commenters said Sections 111 (b) (New Sources) and 111 (d) 

(Existing Sources) are intended to function together, the premise being that new sources have a 

greater opportunity to design and construct in a more efficient, lower emitting manner. The 

commenters said by requiring more stringent standards for existing units, it is clear that EPA has 

expanded the scope and intent of 111 (d). 

Commenters were concerned that the proposed regulations will greatly increase the costs its 

members pay for electricity and raise several cost-related issues: 

• The Proposed Regulation imposes substantially more stringent emission 

requirements for affected, existing generating units in Virginia than the standard 

for new units, yet to be built. 

• The Proposed Regulation fails to recognize substantial, recent investments that 

have significantly reduced carbon dioxide and other emissions in Virginia. 

• The Proposed Regulation fails to recognize Virginia's significant investment in 

and utilization of nuclear generation and, in fact, effectively penalizes Virginia for 

this zero-carbon generation. 

• The Proposed Regulation incorporates generic and unsupported expectations of 

levels of renewable generation and energy efficiency that, when applied to 

Virginia, are extremely ambitious, almost certainly unachievable, and 

uneconomic under traditional standards. 

Commenters stated of particular concern is the proposed emission rates for Virginia are too low 

to provide the Commonwealth with meaningful options for compliance. The commenters said 

given the limited options afforded Virginia, compliance can only be achieved at a cost to 

Virginia that would be significant; analyses of utility planning data, for example, indicate that, 

using conservative assumptions, the incremental cost of compliance for one utility operating in 

Virginia would conservatively be $5.5 to 6.0 billion on a net present value basis. 
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Commenters stated the impact on Virginia would be particularly severe because it will put at 

risk at least two new NGCC facilities that commenced construction before the Proposed 

Emission Guidelines were published in the Federal Register. Commenters said moreover, 

because Virginia's goal of 810 lb/MWh is well below the lowest CO2 emission rate a new stateof-the-art NGCC can achieve, it is possible that no NGCC plants will be built in Virginia in the 

future because it may not be economical to do so. 

Comment 309: VA - Goal Opposition - Disparity from other states

Response 309: See section I.A. of the final rule preamble of the CPP and the CO2 Emission 

Performance Rate and Goal Computation TSD for CPP Final Rule supporting the final CPP for 

the EPA’s response to this comment.

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

Commenters stated Virginia's rate-based CO2 emission performance goals are significantly more 

stringent than the goals for its neighboring states. The commenters said a stark example is West 

Virginia, Virginia's final goal of 810 pounds of CO2 per MWh is twice as stringent as West 

Virginia's final goal of 1620 pounds of CO2 per MWh. The commenters said CAA Section 111 

is a source-based regulatory program; Section 111(d) authorizes the states (or EPA) to establish 

"standards of performance for any existing source" that would be subject to regulation under 

Section 111(b) if it were a new source. The commenters said setting different state-based 

emission requirements is incompatible with this source-based approach; the requirement should 

apply uniformly to the entire source category, taking into account an existing source's remaining 

useful life. The commenters said setting different CO2 emission targets on a state-by-state basis 

violates this principle and would hold similarly situated EGUs located in different states to 

different emission reduction standards; for example, two identical EGUs built at the same time 

using the same technology may be faced with radically different emission reduction obligations 

under EPA's proposed rule simply because of the relative availability of natural gas and 

renewable energy resources in the states where they are located. The commenters asserted it is 

arbitrary and capricious for EPA to propose a rule under which sources in Virginia will suffer 

much higher "per ton" compliance costs than equivalent sources in West Virginia or other states. 

Commenters stated a central premise of any fair and reasonable regulatory scheme is that like 

sources should be treated similarly; this is particularly true in the case of GHG emissions where 

the pollutant at issue is truly global in nature and there are no localized impacts that could justify 

treating similar sources differently. The commenters said thus, after taking into account 

remaining useful life and other related factors, the standards of performance established under 

CAA Section111 (d) should apply uniformly to all existing sources; EPA's proposed emission 

reduction targets fail to meet this goal. 

Commenters stated that despite the impressive progress Virginia has made reducing CO2 

emissions and developing its low carbon intensity electric generating system, the "Four Building 

Block" approach of the Proposed Emission Guidelines assigned the Commonwealth a final goal 

of 810 pounds of CO2 emitted per megawatt hour of electricity generated from "affected" fossil 
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fuel-fired units. Commenters said the goal proposed for Virginia is substantially lower and 

stricter than that assigned to most other states with generating systems of greater carbon 

intensity. Commenters said that although the "Four Building Block" approach taken by the 

proposal to regulate each state according to its potential to reduce CO2 emissions appears 

reasonable at first glance, it creates state-by-state imbalances in compliance obligations and 

costs, is inconsistent with the Clean Air Act's objective to achieve nationally consistent 

standards, and is unfair to states that have achieved lower carbon-intensive electric generating 

systems.

Comment 310: VA - Goal Opposition - more stringent than New Sources

Response 310: See preamble section V.B.7 for a response to the comment regarding 111(b) and 

111(d) rate comparision.

Based on comments received, the EPA is promulgating a final expression of the BSER as 

subcategory rates, where every EGU in a given affected subcategory is given the same rate. This 

addresses some of the commenters concern about inequitable treatment of technologies 

depending on geographic location.

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

Commenters stated the Proposed Regulation arbitrarily, capriciously, and unlawfully imposes a 

standard for affected, existing generating units that is more stringent than the standard for new 

units. The commenters said the Proposed Regulation requires existing fossil fuel units located in 

Virginia to achieve a carbon emission rate that is as much as 26% lower than the carbon 

emission rate that the EPA recently determined can be achieved by new units using the best 

available control technology. The commenters said compared to Virginia's Mandatory Goals of 

884 and 810 pounds of CO2/MWh," the new source performance standard for a new coal unit is 

1,000 to 1,050, and for a new gas unit is 1,100. The commenters said thus, a new fossil unit in 

Virginia - which can only be constructed using the absolute best control technology and without 

physical and other engineering limitations attendant to existing infrastructure - faces a far less 

stringent compliance requirement than existing units. 

Commenters turned regulation on its head in this way - requiring older, but still useful equipment 

to meet a standard that the EPA admits cannot be achieved even by entirely new equipment - is a 

recipe for stranding prior investments and requiring significant additional investment, both of 

which will likely be paid for in large part, if not entirely, by consumers. The commenters said in 

finalizing its Proposed Regulation, the EPA should correct this irrational and inequitable result, 

consistent with the logic found elsewhere in the Proposed Regulation. The commenters said 

when considering carbon capture and sequestration, for example, the Proposed Regulation 

recognizes that modifications of existing units "entail additional considerations beyond those at 

issue for new units" - including the expectation that such costs "would be expected to be 

substantial," and that "some existing EGUs might have space limitations and thus might not be 

able to accommodate...expansion." The commenters said existing generating units cannot 

rationally be expected to achieve more than new units of the same type. The commenters said 
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there is no legal or rational basis to set Virginia's Mandatory Goals for existing units below the 

standards required for new units; this is arbitrary and capricious regulation at its plainest.

Commenters stated EPA's NODA presents some alternative proposals that would make the 

Mandatory Goals for Virginia more stringent. The commenters cannot support any aspect of the 

NODA that would contribute to a carbon emission rate for existing generation facilities in 

Virginia that is more stringent than the standard for new facilities.

Comment 311: VA - Goal Opposition - BB1, BB2, coal retirements, re-dispatch

Response 311: See sections V.C. and V.D. of the final rule preamble of the CPP for the EPA’s

response to this comment and more information about Building Blocks 1 and 2. In the final 

CPP, the compliance period for the interim rate begins in 2022. However, because the interim 

rate reflects an average performance over an eight year period, the EGUs have an option to begin 

reduction later than 2022 as well. As provided in section VII of the preamble, the state mass 

goal for Virginia is well above the 20 million metric tons reflected below.

Neither the proposed or final rule assumes a heat rate improvement at oil-fired EGUs.

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

Commenters stated the two mandatory carbon emission rate goals assigned to affected fossil-fuel 

electric generation units located in Virginia ("Mandatory Goals") substantially limit Virginia's 

options for complying in the compressed timeframe required by the Proposed Regulation. The 

commenters said the carbon emission rate on Virginia's existing fossil-fuel electric generation 

units ("EGUs") imposed by the EPA, beginning in 2020, is substantially more stringent than the 

standard that EPA has identified for new fossil-fuel units using the best available control 

technology. The commenters said to achieve Virginia's Mandatory Goals, production from 

existing fossil-fueled power plants not currently intended for retirement would need to be 

significantly reduced.

Commenters stated as released on November 6, 2014, the EPA's mass-based compliance 

calculation of 20.6 million annual metric tons of carbon emissions for Virginia during the interim 

compliance period of 2020-2029 further confirms EPA's expectation of generation retirements 

beyond those that are currently planned. The commenters said operating the 7,055 megawatts of 

affected natural gas combined cycle units in Virginia (including the two stations currently under 

construction) at the 70% capacity factor EPA identifies as an achievable best practice in its 

second compliance target "building block" for such facilities would produce approximately 17.1 

million metric tons of carbon emissions. The commenters said but since the Proposed Regulation 

effectively caps emissions at 20.6 million metric tons, on average for 2020-2029, only 3.5 

million annual metric tons could be emitted from the remaining 5,800 megawatts of affected 

existing units not currently planned for retirement or fuel conversion. The commenters said by 

2030, this 5,800 megawatts of existing generation becomes further constrained by the Proposed 

Regulation, as the EPA-calculated cap for Virginia decreases to 18.9 million metric tons of 

carbon emissions in 2030 - leaving only 1.8 million metric tons of such emissions after Virginia's 

affected natural gas combined cycle generation operates at EPA's 70% capacity factor.
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Commenters stated EPA's calculations illustrate the substantial constraint that the Mandatory 

Goals establish on generation in Virginia currently used to maintain reliable electric service at 

just and reasonable rates to customers. The commenters said although the affected oil units in 

Virginia operate as peaking facilities that produce relatively little energy on an annual basis, the 

five largest coal units in Virginia operated at capacity factors between 60% to 82% during a 

recent twelve-month period (April 2013 to March 2014). The commenters said these five units, 

which total approximately 2,500 megawatts, are located at three different power stations. The 

commenters said the EPA's first "building block" for calculating the emission targets for Virginia 

assumes that these units will increase their productivity by 6%; however, coal generation at any 

one of these three power stations can, at recent production levels, exceed the 3.5 million annual 

metric tons remaining for all affected existing coal and oil units in Virginia if, as EPA assumes, 

combined cycle generation in Virginia can achieve a 70% capacity factor. The commenters said 

operating only these five coal units at a mere 17% capacity factor during 2020-2029, or a 8% 

capacity factor beginning in 2030, would cause carbon emissions in Virginia to exceed the 

compliance caps for Virginia identified by EPA's NODA if the natural gas combined cycle fleet 

operates at EPA's 70% capacity factor.

Commenters stated the reality, as recognized by, among others, EPA and the North American 

Electric Reliability Corporation ("NERC"), is that the Proposed Regulation, if adopted, is 

expected to cause a second wave of retirements of coal-fired generation units shortly after the 

upcoming retirements caused by the MATS Rule. The commenters said a key difference between 

the MATS retirements and those expected from the Proposed Regulation is the type of power 

plants that the Proposed Regulation places at risk of retirement and, more specifically, the extent 

to which customers rely on those power plants. The commenters said EPA's modeling results, 

and basic math using EPA's mass-based compliance caps for Virginia, show that the Proposed 

Regulation is expected to cause the retirement of dispatchable, base load facilities that currently 

generate a large quantity of power. The commenters said for example, EPA's 2012 data identifies 

approximately 657,000 megawatt-hours of total electric generation from the two coalfired units 

at the Yorktown Power Station already planned for retirement due to the MATS Rule; in 

contrast, coal-fired generation at the base load Chesterfield and Clover power stations for the 

same year were 3.6 million and 4.4 million megawatt-hours, or approximately 6 and 7 times such 

generation from the retiring Yorktown units. 

Comment 312: VA - RE and EE

Response 312: See sections V.A. and V.E. of the final rule preamble of the CPP for the EPA’s

response to this comment and more information about Building Blocks 3 and 4.

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

Commenters’ analysis shows that Virginia can achieve its remaining reductions through a 

combination of renewable resource additions and increased energy efficiency investments. The 

commenters said renewable energy and energy efficiency have been adequately demonstrated in 

Virginia to be a cost-effective and clean way to meet our energy needs. The commenters said VA 
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is already beginning to make investments in these clean energy technologies, and we can do 

much more. 

Commenters stated Virginia would only need to achieve a fraction of the renewable and energy 

efficiency goals that are already set forth in the Virginia Code and the Virginia Acts of Assembly 

to reach the carbon reduction target. The commenters said Virginia's General Assembly enacted 

a voluntary Renewable Energy Portfolio Standard goal in 2007, which now states that electric 

utilities would procure 15 percent of electric sales from renewable resources. The commenters 

said this voluntary goal is readily achievable; in addition, the Virginia General Assembly 

established a goal of reducing electricity consumption by 10 percent by 2022. The commenters 

said the Virginia State Corporation Commission has found that this energy efficiency goal is 

reasonable and achievable. The commenters said if Virginia were to achieve just 50 percent of 

both of these voluntary goals, it would reach the 810 lbs/MWh emissions rate. 

Commenters stated if EPA modified its methodology in line with the recommendation provided 

in its October 28, 2014 NODA by assuming that the level of incremental renewable energy and 

energy efficiency resources would reduce proportionally the level of existing coal and gas fired 

generation, Virginia would only need to achieve 37 percent of both goals. This represents 

roughly half of the renewable energy and energy efficiency levels that EPA assumed in building 

blocks 3 and 4. 

Commenters stated if Virginia were to get credit for 100 percent of its energy efficiency 

investments - rather than 58 percent - it would only need to achieve 31 percent of the renewable 

energy and energy efficiency goals. 

Commenters requested clarification about the Annual Renewable Energy Generation for Virginia 

in 2012. The commenters said in the Proposed Renewable Energy Approach Excel file provided 

by EPA, the 2012 RE (MWh) number for Virginia is 2,358,444, which the commenters traced 

back to the EIA's Annual Generation by State data file. The commenters said using ""Wood and 

Wood Derived Fuels"" and ""Other Biomass"", the commenters were able to get the same 

number; however, when the commenters looked at the 2012 Unit Level Data using e-Grid 

Methodology file provided by EPA, using those same fuel types (BLG, LFG, MSB, OBG, 

WDS), the commenters calculated 2,713,084. The commenters asked what is not being included 

in the first files that is being included in that last file.

Comment 313: WA - See no reason to limit the amount of new RE expected of Washington 

based on its 2012 fossil generation

Response 313: See section V.E. of the final rule preamble of the CPP for the EPA’s response to 

this comment and more information about Building Block 3.

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

Commenters stated EPA asks whether "the difference between a state's RE generation target and 

its 2012 level of corresponding RE generation does not exceed the state's reported 2012 fossil 

fuel-fired generation." Id. at 34,868-69. Commenters said this issue only affects Washington, 
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whose 2012 fossil generation (9.4 million MWh) is less than the amount of new generation from 

renewables the state would produce if it met its RE generation target under Block 3(15.9 million 

MWh). Commenters stated they see no reason to limit the amount of new RE expected of 

Washington based on its 2012 fossil generation. Commenters said that strategy might make sense 

if EPA's plan supposed that each and every new MWh from RE were to replace an MWh from 

an existing fossil unit, but that is not the case: at least some of that new RE generation will meet 

demand growth rather than displace existing fossil generation. Commenters said Washington 

also imports some power from neighboring states, much of which is from fossil generating units. 

Commenters said and even if that additional 15.9 million MWh of clean energy were to displace 

all fossil-fired generation and exceed the state's demand growth, Washington could sell any 

additional clean electricity to nearby states, such as Montana and Wyoming, which lack strong 

renewable industries. Commenters stated finally, it is worth noting that under EPA's current plan, 

Washington is not expected to actually meet its state RE target, but need only meet the regional 

growth factor. Commenters said as such, Block 3 only expects Washington generate an 

additional 9.5 million MWh from RE, which is only marginally higher than its 2012 fossil 

generation of 9.4 million MWh. Commenters stated if the agency decides to retain its proposal 

for Block 3, we urge it to require all states to meet their RPS targets, as noted above, rather than 

simply the regional growth factors. 

Comment 314: WA - The EPA's Dispatch Assumptions (Building Block 2) are Incorrect for 

Setting the Washington State Goals

Response 314: See section V.D. of the final rule preamble of the CPP for the EPA’s response to 

this comment and more information about Building Block 2 and the CO2 Emission Performance 

Rate and Goal Computation TSD for CPP Final Rule supporting the final CPP. EPA’s final rule 

approach to building block two differs from its proposed approach. The fossil steam generation 

supporting the source category rates informing the state goals in the final rule do not assume a 

zeroeing out of coal generation.

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

Commenters stated his organization is an independent power producer (IPP) located in 

Washington State. Commenters said more commonly known as a merchant power plant, his 

organization is a non-utility generating station that sells electricity on a wholesale basis to other 

companies to distribute and deliver to their utility customers. Commenters stated under current 

deregulation of electricity generation, his organization must compete in a free economic 

wholesale power market to sell the power it produces. Commenters said as such, the decisions on 

how much power to generate and when to generate that power (i.e. dispatch the plant) by his 

organization are not governed by any Washington State Utility or Regulatory Agency. 

Commenters stated since the State cannot dispatch the plant to reduce GHG emission rates in any 

manner, the EPA cannot use assumptions of dispatch for his organization in the Washington goal 

calculation. Commenters said the State goal must be adjusted to account for the existing GHG 

reduction agreements between Washington and his organization.
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Commenters stated in 2011, the Washington Legislature passed Senate Bill 5769, which was 

codified at RCW 80.80.040, to regulate the emissions of GHG from his organization and clearly 

define the timeline for GHG reductions from the Plant. Commenters said one of the two coal 

fired Units must cease burning coal by the end of 2020, at that time cutting the facility's GHG 

emissions approximately in half, and the other Unit must cease burning coal by the end of 2025.

Commenters stated while the requirement for his organization to completely cease burning coal 

by the end of 2025 will allow the State of Washington to meet the EPA intentions of eliminating 

GHG emissions from coal fired power generation in Washington by 2030, the staged shutdown 

of his organization means that EPA's proposed 2020 GHG goal for Washington is not 

achievable. Commenters said Washington's 2020 interim goal for reducing GHG by reducing 

coal fired generation must recognize that his organization will be fully operational and 

generating electricity from both coal fired Units through the end of 2020 at levels well above 

2012 levels as described below. Commenters stated per the agreed upon State Law, emissions 

will be reduced to one Unit operating through 2025. Commenters said this staged reduction 

schedule must be addressed by the EPA in the goal setting to allow Washington State to achieve 

the goals developed under the State and the EPA plan.

Commenters stated his organization requests that the EPA update Washington State's interim and 

final emission rate goals to reflect the operational realties of the EPA's incorrect dispatch 

assumptions on the State's only coal plant. Commenters said this must be done to ensure that the 

commitments made by Washington State in exchange for the early shutdown of his organization 

are addressed.

Comment 315: WA - Heat Rate Improvement Measures Already Taken at TCG

Response 315: See section V.C. of the final rule preamble of the CPP for the EPA’s response to 

this comment and more information about Building Block 1 and the CO2 Emission Performance 

Rate and Goal Computation TSD for CPP Final Rule supporting the final CPP.

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

Commenters stated in 2001 and 2002, his organization voluntarily installed wet Flue Gas 

Desulfurization units (FGD's) and low NOx burners to reduce haze and acid rain causing 

emissions. Commenters said this was a major emissions reduction project and included some of 

the heat rate reductions recommended by the EPA in the proposal. Commenters stated the project 

included heat rate improvements from improved combustion controls, upgrades to steam turbine 

efficiencies, and efficient induced draft fans; all projects described by the EPA for improving 

heat rate.

Commenters stated in 2008 and 2009, the coal EGUs were converted to efficiently burn coal 

from the Powder River Basin (PRB) instead of the locally mined coal that they had been 

designed and constructed to burn. Commenters said PRB coals are lower in sulfur, nitrogen, and 

ash but have higher British thermal unit (BTU) content than the local coal and resulted in lower 

emissions of NOx and SO2. Commenters said in order to increase the EGUs efficiency when 

burning 100 percent PRB coal his organization needed to replace heat transfer surfaces to allow 
347

greater steam recovery which included the addition of an economizer bank. Commenters stated 

other changes included enhanced soot-blower controls, reduced pulverizer energy consumption, 

and Electrostatic Precipitator energy management systems.

Commenters stated the FGD and PRB conversion projects were reviewed by the Southwest 

Clean Air Agency (SWCAA) and the Washington Department of Ecology (DOE) for PSD 

applicability and information was also supplied to the EPA regarding the projects for the EPA's 

review. Commenters said for his organization to invest additional capital into heat rate 

improvements (Building Block 1) given prior improvements and such a short remaining lifespan 

for the plant is completely impractical.

Commenters stated as an IPP, his organization regularly reviews and updates operating 

procedures to achieve peak efficiency from our EGUs. Commenters said as such, we have 

previously implemented all of the appropriate operational improvements to reduce heat rate as 

listed in the proposal. Commenters stated there are no additional operational changes on the 

EPA's list that have not already been considered or implemented and which could result in any 

economical heat rate improvement for his organization. Commenters stated his organization 

requests that the EPA update Washington State's interim and final emission rate goals to reflect 

the operational improvements already made at his organization and recognize that no additional 

heat rate improvements are achievable.

Comment 316: WV - West Virginia can achieve the emission reduction targets proposed by the 

EPA

Response 316: For the EPA’s response to this comment, see the CO2 Emission Performance 

Rate and Goal Computation TSD for CPP Final Rule supporting the final CPP.

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

Commenters stated West Virginia can achieve the emission reduction targets proposed by EPA.

Coal - Commenters said the Clean Power Plan recognizes the importance of coal in America's 

energy portfolio. Commenters stated while coal faces economic challenges, coal is projected to 

continue to be the primary electric generating fuel for the United States for at least the next two 

decades (natural gas does not surpass coal for electricity generation until 2035), and coal mining 

will continue to be an important sector of the West Virginia economy under the Clean Power 

Plan. Commenters stated coal will continue to support West Virginia jobs, education, 

infrastructure and important public services under the Clean Power Plan. Commenters said 

important that funds budgeted for carbon capture & sequestration R&D be made available to 

continue to develop this technology.

Natural Gas - Commenters stated the Clean Power Plan recognizes the emission benefits of 

natural gas relative to coal. Commenters said West Virginia has significant natural gas resources 

in the Marcellus Shale that are currently being developed. Commenters stated developing West 

Virginia's natural gas resources and investing in natural gas for electric generation will help the 
348

state comply with the Clean Power Plan, diversify the state's energy economy, and create new 

jobs.

Comment 317: WV – RE and EE

Response 317: See sections V.A. and V.E. of the final rule preamble of the CPP for the EPA’s

response to this comment and more information about Building Blocks 3 and 4 and the CO2 

Emission Performance Rate and Goal Computation TSD for CPP Final Rule supporting the final 

CPP.

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

Commenters stated West Virginia, also has much to gain from its very achievable and realistic 

target under the Clean Power Plan; the state is the third windiest east of the Mississippi and 

already home to six large wind farms. 

Commenters stated in West Virginia there's enough wind power to potentially supply almost 20 

percent of the state's electric needs. 

Commenters stated electric rates that have skyrocketed recently due to an overreliance on one 

fuel source, coal, can be brought down as the state capitalizes on its largely untapped energy 

efficiency resources, saving consumers money on energy and creating jobs simultaneously.

Commenters stated that even if it is assumed that EPA does have the authority it claims to force 

EE goals on states, in so doing it should not arbitrarily discriminate between states. Commenters 

said under its proposed regulation, states like West Virginia that export power are expected to 

meet one hundred percent of the EE goal EPA sets for it while states that import all of their 

power have no EE goals. Commenters said states that produce only a portion of their power have 

EE goals that are scaled down, based on the amount of power they import. Commenters said a 

state's ability, or lack thereof, to produce its own power has no relationship to its ability to 

implement EE measures, yet this is a criterion EPA uses to limit or entirely do away with EE 

goals. Commenters continued this regulation would make arbitrary distinctions. Commenters 

said states like West Virginia that produce enough inexpensive coal-fired power to export some 

of it to other states will be responsible for reducing carbon emissions from all of this coal-fired 

power, regardless of where it is sold; however, the regulation gives the sales location of 

renewable power controlling weight. Commenters said other states, where the more expensive 

renewable power produced in West Virginia is sold, will be allowed to utilize this renewable 

power in meeting EPA's goals.

Comment 318: WI - Not feasible and almost impossible to meet the proposed reductions in 

carbon emissions without de-commissioning existing circulating fluidized bed (CFB) units.

Response 318: For the EPA’s response to this comment, see the CO2 Emission Performance 

Rate and Goal Computation TSD for CPP Final Rule supporting the final CPP.
349

The EPA understands the unique circumstances of the The Kewaunee Nuclear Plant closure. It 

has not made an adjustment to the baseline or the final Wisconsin state goal. EPA has 

consistently used a 10% threshold when considering similar adjustments for unit outage or hydro 

concerns. While it recognizes the immediate impact on fossil generation in 2013, the first year 

of compliance in the final CPP had been moved to 2022 – which provides more time for changes 

in the states power supply. Moreover, the EPA notes that there are significant capacity additions 

(e.g., under construction capacity) in the same region that are accounted for elsewhere in the 

baseline thay could conceivably be providing replacement generation for scheduled closures 

such as this one. For more information about how the final goals were calculated please see the 

CO2 Emission Performance Rate and Goal Computation TSD for CPP Final Rule supporting the 

final CPP.

Additionally, EPA has not made any adjustements for planned closures. There are a varirety of 

closures expected across regions in the coming years from both fossil and non-fossil sources. 

Adjsuting the historical baseline for all of these closures would require projecting where the 

replacement generation would come from. This would move the baseline analysis from a 

historical basis towards a projected one. EPA believes the regions on average will experience 

closures that facilitate movement towards compliance (e.g., closures of higher emitting sources), 

and therefore views it as conservative to not make adjustments for closures. For example, 

Wisconsin also has significant amoutns of coal steam capacity that appear to scheduled to require 

during the same timeframe as Kewaunee. Making an adjustment for one type of closure (e.g., 

nuclear), but the other types (high emitting fossil) would introduce a bias to the baseline.

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

Commenters stated their organization is a community owned, not-for-profit utility located in 

Manitowoc, Wisconsin and has two coal/petroleum coke/biomass-fired and two natural gas-fired 

units totaling 118 MW of fossil-fired generation. Commenters stated it is not feasible and almost 

impossible for his organization alone to meet the proposed reductions in carbon emissions 

without de-commissioning our existing circulating fluidized bed (CFB) units. Commenters said 

this action would make our community totally dependent on an outside supply of electricity and 

a significant upgrade of the transmission supply would be required to provide reliable energy to 

our citizens. 

Commenters stated our rate payers invested over $80 million into our newest CFB unit and it is 

less than 10 years old. Commenters said the CFB technology was identified as "Clean Coal 

Technology" by the Department of Energy and was one of the reasons MPU selected this 

technology. Commenters stated in fact this unit was selected by the EPA as one of the floor units 

for the new MATS rule. Commenters said as a new unit it was built to be as efficient as possible 

and an expectation that they or any other utility left 6% waste on the table is nonsensical. 

Commenters stated the possibility that they may needlessly strand the largest investment their 

City has ever made is frightening.

Commenters stated Wisconsin will not be able to comply with block 3 as they already lost one of 

their two nuclear power plants when the Kewaunee 600 MW plant was closed. Commenters said 

they fail to see where this loss was included in the EPA analysis for Wisconsin.
350

Comment 319: WI - Analysis of Wisconsin's Compliance Options for Compliance with the 

EPA's Clean Power Plan 

Response 319: See section I.A. of the final rule preamble of the CPP and the CO2 Emission 

Performance Rate and Goal Computation TSD for CPP Final Rule supporting the final CPP for 

the EPA’s response to this comment. Also see section VIII of the preamble which discusses 

compliance pathways and options.

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

Commenters stated this analysis used two energy modeling tools to compare the costeffectiveness of two strategies Wisconsin could choose to achieve compliance with the EPA's 

CO2 standards for existing electric generating units. Commenters said the analysis compares a 

30% by 2030 RPS against a natural gas switching scenario in conjunction with the state's 

existing 10% RPS to achieve the 2030 CO2 intensity reductions. Commenters stated using the 

MyPower economic dispatch model, and a groundup spreadsheet model based on data from the 

EPA's technical support documents, this analysis shows that the 30% RPS will achieve deeper 

CO2 reductions at a lower cost than the fuel switching scenario by the late 2020's. Commenters 

said the analysis also shows that the 30% RPS can insulate utilities and ratepayers against fossil 

fuel price volatility by comparing the two scenarios and applying historical natural gas prices to 

calculate total cost estimates.

Commenters stated this analysis is meant to provide an independent, alternative viewpoint in 

addition to work done by the Wisconsin Department of Natural Resources and the Public 

Services Commission. Commenters said it does not address electric reliability, transmissions or 

natural gas distribution/supply constraints. Commenters stated however, further research will be 

pursued to quantify the amount of new natural gas pipelines needed to support the fuel switching 

scenario.

Commenters stated in summary, Wisconsin can achieve significant CO2 reductions by pursuing 

a 30% by 2030 RPS. Commenters said the 30% RPS is a more cost-effective option for 

Wisconsin's utilities and ratepayers over the long-term, as well as a hedge against unpredictable 

fossil fuel prices. Commenters stated Wisconsin should not fight implementation of the Clean 

Power Plan, but embrace it as an opportunity to stimulate new economic growth in the clean 

energy and smart grid sectors.

Comment 320: WI - The EPA must adjust Wisconsin's baseline to account for the May 2013 

closure of Kewaunee Nuclear Plant.

Response 320: See section V.E. of the final rule preamble of the CPP for the EPA’s response to 

this comment and more information about Building Block 3 and the CO2 Emission Performance 

Rate and Goal Computation TSD for CPP Final Rule supporting the final CPP. See response 

318.
351

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

Commenters stated the Kewaunee Nuclear Plant, which provided 7.3% of Wisconsin's electricity 

generation in 2012, closed in May of 2013, resulting in increased generation (and emissions) 

from fossil generators working to fill the void. Commenters said the EPA must adjust 

Wisconsin's 2012 baseline to account for the replacement of the retired, carbon-free generation 

from Kewaunee. Commenters stated we discuss possible approaches the EPA could take to this 

adjustment in our Technical Corrections document.

Comment 321: WI - building block 2

Response 321: See sections V.D. and VI of the final rule preamble of the CPP for the EPA’s

response to this comment and the CO2 Emission Performance Rate and Goal Computation TSD 

for CPP Final Rule supporting the final CPP.

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

Commenters stated the highest annual capacity factors for the Wisconsin NGCC fleet is 37%. 

Commenters said the EPA should therefore assume, when developing building block 2 goals, 

that this is the maximum capacity factor available to Wisconsin. 

Commenters stated 2012 was an outlier for NGCC operation in Wisconsin. Commenters said the 

state's capacity factor in 2012 (46%) is approximately 70% higher than the average capacity 

factor for the entire NGCC fleet from 2005 through 2013 (28%). Commenters stated this 

supports the contention that 2012 was an unusual year and must not be used as the sole year in 

determining achievable NGCC capacity factors for each state. Commenters said note that, if 

2012 is treated as an outlier and removed from the analysis, the three-year average capacity 

factor would be just 29%.

Commenters stated Based on the 2012 eGrid dataset, only one of Wisconsin's 35 natural gas 

plants operated at a capacity factor above 50% (the 620MW Fox Energy Center at 53%). The 

commenters said only four other natural gas plants operated at capacity factors above 20% (Port 

Washington Generating Station, Domtar Paper Mill, LSP-Whitewater and the Rhinelander Mill) 

and 24 plants operated at capacity factors below 5%; Wisconsin has an abundance of natural gas 

capacity that is severely under-utilized. 

Commenters stated for WI power sector pursuing a 30% RPS by 2030 would result in natural gas 

plants larger than 50MW operating at a capacity factor of 25-26% in 2030; this is well below the 

EPA target of 70% and represents a level of fuel consumption that should not be difficult to meet 

without modest improvements to Wisconsin's existing natural gas delivery infrastructure. The 

commenters said the 30% RPS scenario results in natural gas consumption of an estimated 171 

million mcf per year compared to 126 million mcf under the business-as-usual (BAU) scenario. 

Commenters stated this represents an increase of 35% over 15 years, or 2.4% per year; the 30% 

RPS scenario also assumes that all coal plants that operate at capacity factors below 50% will be 

idled or retired with the generation gap being filled by increased dispatch of natural gas and new 
352

renewables; as a result, coal consumption under the 30% RPS scenario is estimated at 9 million 

short tons in 2030 compared to 28 million tons under the BAU scenario. The commenters said 

from 2014-2030, coal declines from 52% of Wisconsin's total generation to 20%, while natural 

gas increases from 17% to 25%; renewables account for 30% of total generation and nuclear 

accounts for 16%. The commenters said under the BAU scenario, coal holds steady at 51%, 

natural gas rises slightly to 21%, nuclear makes up 20% (assuming Dominion's Kewaunee plant 

reopens), and renewables account for just 6% of total generation. 

Commenters stated in 2014, 15 of Wisconsin's 35 coal-fired units larger than 25MW are at least 

50 years old and 22 will be that age or older in 2020. The commenters analyzed a scenario where 

Wisconsin meets EPA's CO2 reduction targets by displacing coal with increased dispatch of 

natural gas; under this scenario, renewables are held constant at current levels that reflect the 

10% by 2015 RPS, natural gas is increased to the point where Wisconsin meets EPA's systemwide CO2/MWh target, and coal is reduced proportionally. The commenters said by 2030, 

natural gas would account for approximately 56% of Wisconsin's total generation, while coal 

declines to around 23%. Natural gas plants larger than 50MW will operate at capacity factors of 

58% (compared to 27% under the 30% RPS scenario), and total natural gas consumption will rise 

to 384 million mcf. The commenters said this is triple the amount of gas consumed under the 

BAU scenario and more than double the amount consumed under the 30% RPS scenario. The 

commenters said this level of consumption would likely require large-scale, capital intensive 

expansion and upgrades of the existing natural gas distribution network. 

Commenters stated pursuing a massive shift toward natural gas to meet the EPA targets would 

also make Wisconsin's utilities, electric customers and economy extremely vulnerable to 

historically volatile natural gas prices; it would also expose utilities to the risk of CO2 

compliance costs if a state, regional or national emissions trading program were implemented in 

the future. The commenters said while the results of this analysis show that Wisconsin could 

meet EPA's carbon reduction targets without ramping its natural gas units up to a 70% annual 

capacity factor, it highlights the risks inherent in pursuing a one fuel compliance strategy. The 

commenters said the 30% RPS strategy results in a diversified energy mix with much lower 

exposure to fuel price volatility and potential CO2 compliance costs. The commenters said other 

Midwestern states are pursuing far more aggressive RPS goals on shorter timelines that have 

stimulated job growth; Wisconsin can and should take a similar path. 

Comment 322: WI - Adjustments to the EPA's Emission Rates for Wisconsin

Response 322: For the EPA’s response to this comment, see the CO2 Emission Performance 

Rate and Goal Computation TSD for CPP Final Rule supporting the final CPP.

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

Commenters stated four scenarios were tested to adjust the EPA's rate-based goals for the state 

for the loss of Kewaunee's carbon-free generation. All provide similar results.
353

Commenters stated Scenario 1: Replacement with coal. Commenters said this scenario assumes 

that all of the 2012 generation from Kewaunee would be taken up by the newer coal plants (Elm 

Road and Weston 4), which have enough extra capacity to do so.

Commenters stated Scenario 2: Replacement with NGCC and coal. Commenters said this 

scenario assumes that Kewaunee's 2012 generation would be made up by NGCC and coal units 

in the proportions in which they expanded from 2011 to 2013 (72% NGCC and 28% coal).

Commenters stated Scenario 3: Commenters said replacement with NGCC, coal and renewables. 

Commenters stated this scenario assumes that the generation would be made up by NGCC, coal 

and renewables units in the proportions in which they expanded from 2011 to 2013 for the fossil 

units or 2012 to 2013 for renewables (66% NGCC, 25% coal, and 8% renewables). Commenters 

said note that PSCW expects this amount of additional renewable generation to be added in 2014 

irrespective of this rule.

Commenters stated Scenario 4: Commenters said 12 month baseline from July 2013 to June 

2014. Commenters stated for this scenario, the actual generation was analyzed for the 12 months 

after Kewaunee closed (July 2013-June 2014) based on data reported to the EPA's CAMD and 

determined the estimated net2 MWh of coal, NGCC and oil/gas boilers based on this data. 

Commenters said this data should reflect actual in-state emissions without Kewaunee. Total 

estimated net fossil generation is very similar to the 2012 baseline + 2012 Kewaunee generation. 

Commenters stated the results of these corrections cluster into two sets based on whether 

renewables are allowed to compensate for some of the lost generation. Commenters said the first 

set includes the first two scenarios, in which all of the generation is assumed to be replaced by 

fossil sources. Commenters stated the goals for these two scenarios are identical after applying 

building blocks 1 and 2 because the total amount of fossil generation remains the same as does 

the amount of NGCC capacity, so the emissions from coal and NGCC are the same after 

expanding NGCC operation to 70% of capacity. Commenters said the second set includes 

replacement by fossil and renewables and the actual 12-month generation (2013-14 - in which 

renewable energy was in the system; scenario 4). Commenters stated these scenarios end up with 

identical goals, likely because both analyses rely on data from 2013. Commenters stated all of 

these scenarios give similar adjusted overall goals, with final goals of 1271-1277 lbs CO2/MWhnet. Commenters said all of these goals are less stringent in comparison with the proposed goal 

of 1203 lbs CO2/MWh-net. Commenters stated these adjusted goals more accurately reflect the 

current status of Wisconsin's power sector, and the EPA must adjust the state's goal in a similar 

manner to reflect the significant impact of the retirement of the Kewaunee Nuclear Plant.

Commenters stated if the EPA uses a multi-year baseline as we recommend in our general 

comments, the EPA should make the Kewaunee adjustment based on as many years of data as 

they can. Commenters said the EPA is unlikely to have three years of post-retirement data 

available but should use data from as long a time period as is available at that point.

Comment 323: WI - The EGEAS runs demonstrate the necessity of staging rule requirements 

and allowing states to determine the appropriate schedule for interim requirements.
354

Response 323: See section I.A. of the final rule preamble of the CPP for the EPA’s response to 

this comment and the CO2 Emission Performance Rate and Goal Computation TSD for CPP 

Final Rule supporting the final CPP.

EPA’s interim performance rates and goals do not begin until 2022 in this final CPP Rule. 

Moreover, there are no new NGCC builds assumed in their estimation. EPA believes 

states/EGUs have a variety of compliance options available to them to meet the emission 

guidelines without building new generation.

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

Commenters stated the modeling runs indicate that at least 1,800 to 2,400 megawatts (MW) of 

new NGCC capacity will have to be built by 2020 in order to meet the interim goals as currently 

proposed by the EPA. Commenters said this is a substantial undertaking that will have to go 

through environmental permitting processes and approval by PSCW. Commenters stated it is 

questionable whether the amount of new NGCC capacity can be permitted and built by 2020. 

Commenters stated it is estimated that such work would require five to seven years from start of 

the process to bringing the units online. Commenters said if a state rule is not approved until 

2019, the new NGCC units would not be available until 2024 to 2026 at the earliest. Commenters 

stated this modeling performed by the PSCW shows the importance of allowing states to 

determine the appropriate schedule for reducing carbon emissions.

Commenters stated PSCW conducted several EGEAS modeling runs, including a reference case 

run, to evaluate EPA's proposal under various conditions and assumptions; in all of the runs, the 

model was allowed to optimize electric generating units (EGU) dispatch in meeting the same 

electricity load. The commenters said the electricity load was projected by applying the MISO 

growth rate of 0.8% per year based on 2012 Wisconsin electricity sales plus transmission losses; 

in-state and out-of-state EGUs dedicated for Wisconsin plus additional market purchases were 

dispatched in an optimized manner. The commenters said EGEAS estimates 13 percent of 

Wisconsin's electricity to be generated from out-of-state capacity in 2014, plus a smaller 

percentage of out-of-state energy purchases. The commenters said the in-state EGUs available 

for operation under the EGEAS model do not include the Kewaunee nuclear plant that was 

shutdown in 2013. 

Commenters stated in all of the runs, the model was allowed to pick from various new options in 

meeting CO2 requirements and load demand, including additional energy efficiency measures, 

renewable energy generation, natural gas combined cycle, and combustion turbines. 

Commenters stated assumptions were also made so that the building blocks presented by the 

proposal could be applied realistically to Wisconsin's fleet; for building block 1, a 6% heat rate 

improvement is not feasible for Wisconsin's coal-fired fleet; the maximum HRI potential may 

range from 0.5% to 2.3% of the gross heat rate. The commenters said PSCW's EGEAS model 

runs assumed an ambitious 3% heat rate improvement for units that were not built after 2005, 

supercritical units, or retiring during the compliance period; because the results tended to show 

coal-fired generation running at less than full capacity, which often negates HRI investments, no 

additional improvements were included for any of the limit runs. 
355

Commenters stated due to the ambiguity of the proposed rule, multiple assumptions were made 

to determine the final mass-based goal for Wisconsin; for example, the emission rate formula, as 

stated in the draft rule, uses "in-state, non-hydro renewable resources" in setting the baseline 

renewable generation in the denominator of the formula. The commenters said this may be 

correct if Wisconsin was an island that did not import or export electricity; however, Wisconsin 

is an importing state connected to the rest of MISO, and relies heavily on out-of-state renewable 

resources to meet the renewable portfolio standard (RPS). The commenters said while this 

renewable generation might not be in Wisconsin's emission rate baseline, this generation would 

most likely be in Minnesota's and Iowa's baseline. The commenters said if the current rule counts 

these out-of-state renewable resources for the states in which they are located, this will change 

these respective states' baselines and this will make their goals more stringent. 

Commenters stated another assumption made for the purpose of modeling was to increase the 

mass-based goal proportional to the amount of non-renewable energy imported from other states. 

The commenters said the treatment of out-of-state resources dedicated to Wisconsin is not 

clearly addressed in the Clean Power Plan as proposed; for example, Minnesota may be 

responsible for reducing carbon emissions attributable to the non-renewable energy it exports to 

Wisconsin. The commenters said as a result, there will be extra costs associated with compliance 

in exporting states; as it is unlikely that ratepayers in exporting states will cover the costs 

associated with generation allocated for supplying out-of-state load, these costs will be passed on 

to Wisconsin ratepayers in some form, either through increased rates for imported electricity or 

through construction of new generation in Wisconsin to meet the load currently being met with 

imports. The commenters said it is necessary to take into account out-of-state resources in 

determining an actual cost of compliance to Wisconsin ratepayers. 

Comment 324: WI - Renewable Energy

Response 324: See section V.E. of the final rule preamble of the CPP for the EPA’s response to 

this comment and more information about Building Block 3 and the CO2 Emission Performance 

Rate and Goal Computation TSD for CPP Final Rule supporting the final CPP.

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

Commenters stated the EPA sets a goal for Wisconsin to produce 7,476 MWh of renewable

electricity by 2030, or 12% of the state's 2012 demand. Commenters said the results of IPM 

modeling forecast that Wisconsin will need to generate 3,977MWh from wind, 1,212 MWh from 

biomass, and 2,287 MWh from hydro to meet the 2030 carbon reduction goal. Commenters 

stated under the 30% RPS scenario, Wisconsin would generate 11.5 million MWh from wind, 

2.1 million MWh from solar, 4.9 million MWh from biomass and 6.8 million MWh from biogas. 

Commenters said coal falls from 51% to 24% of the state's total generating mix (15.2 million 

MWh), while natural gas holds steady at 22% (13.8 million MWh).

Commenters asked is it possible for Wisconsin to expand renewable generation to 11% of total 

generation, what are the associated costs. 
356

Comment 325: WI - Credit for Early Actions of WPS to Reduce CO2 Emissions

Response 325: See sections VI, VIII.B. and VIII.C. 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 the EPA should recognize and provide credit for early actions that reduce 

CO2 emissions. Commenters said not providing credit for investments and actions that reduced 

emissions would penalize electric utilities and their customers. Commenters stated their 

organization has made significant investments in renewable generation and energy efficiency 

programs. Commenters said also, their organization will be retiring Pulliam Units 5&6 and 

Weston Unit 1 by June 2015 and as a result, should be given credit for the avoided CO2 emission 

from June 2015 until the start of the CO2 compliance period. Commenters stated the avoided 

CO2 emissions could be estimated from the 2005 actual CO2 emissions for those units.

Comment 326: WY - Oppose goals

Response 326: For the EPA’s response to this comment, see the CO2 Emission Performance 

Rate and Goal Computation TSD for CPP Final Rule supporting the final CPP. EPA has also 

provided state mass goals as a compliance flexibility in this final rule. Usinga mass based metric 

may better capture some of the reduction actions discussed in the WY PSC analysis. Moreover, 

EPA does allow for the use of out of state NGCC credits and Renewable credits in its final CPP 

which can further facilitate compliance if the state chooses to use a rate based compliance 

approach.

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

Commenters prepared a comparison calculation between the EPA's proposed goal and what they 

felt would be the outer limit of the practical for Wyoming. Commenters presented the 

calculation in a step-by-step manner, making changes to the calculation based on their 

comments. Commenters’ calculations indicated that if three coal-fired generating facilities are 

retired prematurely (Dave Johnston, Naughton, and Jim Bridger), it may be enough to meet 2020 

goal, but even if an additional facility is retired prematurely (Wyodak), they would still be short 

of the 2029 target. Commenters indicated that by the time they got to the 2020 closures, there 

would be serious threats to regional reliability and a financial catastrophe for ratepayers. The 

stranded investments would include not only those associated with the facilities but also regional 

haze compliance related upgrades currently being made to the Jim Bridger facility. Commenters 

requested that the EPA adjust Wyoming's goal to a rate that poses a fair and reasonable challenge 

to comply.

Specific changes to calculations are not detailed here, but commenters made the following 

general comments concerning the EPA's goal calculation:

The misuse of gross renewables generation is a central problem in the EPA's proposed goal, one 

which renders meaningless any general appeal to flexibility
357

The Block 1 goal cannot be sustained because the other Blocks work against heat rate by 

reducing plant capacity

The EPA goal poses an enormous risk for the State: no solution may emerge, particularly 

between now and 2020, to close the enormous gap between the goal and the practical reality.

Their analyses eliminated plants in order of scheduled full depreciation dates, because this would 

minimize stranded investment, although they realize this is not necessarily how state would 

proceed.

It is not clear what incentive a state will have to assume responsibility for the Section 111(d) 

program if the only foreseeable result is catastrophe - besides risk that if state does not assume 

responsibility the EPA will claim broad enforcement powers under the guise of state law 

pertinent to the state plan

Commenters stated the Proposed Rule sets a CO2 emission rate for Wyoming based on the 

EPA's determination of what constitutes a "Best System of Emissions Reduction" ("BSER") for 

all existing power plants on a state-wide basis. Commenters said the Proposed Rule rejects the 

possibility of a "less stringent standard" or final compliance time. Commenters stated instead, 

the Proposed Rule requires that any Wyoming CAA Section 111 (d) Plan must show 

"achievement of emission performance equivalent to the goals established by the EPA, on a 

timeline equivalent to that in the Proposed Rule." Commenters said under the Proposed Rule, 

Wyoming would be required to reduce the CO2 emissions rate of its electric generating fleet by 

19 percent. Commenters stated what this means is the Proposed Rule, if approved, will force 

Wyoming to revamp nearly all aspects of its electricity generation, changing the way utilities 

regulated by the Commission select generation resources, dispatch and operate those resources, 

consider the useful and remaining lives of existing resources, invest in generation and 

transmission infrastructure, and in turn, deliver that electricity to consumers within Wyoming. 

Commenters stated the Agency's renewable energy targets (based on inaccurate analysis) are 

unachievable by Wyoming. Commenters said the EPA, in developing a target, incorporated all of 

the renewable energy generated in Wyoming when only 15% of this renewable energy is 

consumed in-state. Commenters stated this simplistic approach and the EPA's required growth 

rate would require Wyoming to increase its consumption of wind energy from 666,212 megawatt 

hours of wind energy in 2012 to 9,427,996 megawatt hours by 2030. Commenters said this 

represents a 1,415% increase in intrastate consumption of wind energy (equating to a 52% RPS). 

Commenters stated Wyoming will not have the demand to meet this excessive supply of 

electricity nor the infrastructure to support it.

Commenters stated the Agency is frontloading emission reductions; Wyoming's carbon emission 

rate in 2012 was 2,115 lbs/MWh. The commenters said in 2020, the first year of compliance, the 

EPA expects Wyoming to reduce emissions to 1,899 lbs/MWh- representing 10% of the required 

19% reduction in year one; this requirement is not present for many other states. The 

commenters said the EPA claims to have given broad authority to states to determine the most 

reasonable compliance path, but the stringent and rushed deadlines leave few options.
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Commenters were concerned about the calculations that resulted in Wyoming's emission goal. 

The commenters said the Wyoming Public Service Commission (PSC) has provided an in-depth 

analysis of the outright errors and unreasonable assumptions that undergird EPA's calculation of 

Wyoming's proposed state goal. The commenters said EPA proposes state goals based on a statespecific analysis of available efficiency gains from each of the four building blocks; Wyoming's 

state goal as proposed by EPA is based upon clear errors and irrational assumptions; as a result, 

EPA's proposed action is arbitrary and capricious.

Comment 327: WY - Support for goals

Response 327: The EPA appreciates the support for the goals, please see the CO2 Emission 

Performance Rate and Goal Computation TSD for CPP Final Rule for the final goals.

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

Commenters stated the goal for CO2 pollution from Wyoming EGU would be a reduction in the 

2012 emission rate of 2,115 pounds of CO2 per megawatt of electricity generated to a level of 

1,714 lb/MWh by 2030; this represents about a 19 percent reduction in CO2 emissions from 

Wyoming EGU; the overall goal of EPA's goals nationwide is a 30 percent reduction in CO2 

emissions by 2030 compared to 2005 emissions levels. The commenters said given that 

Wyoming has the third highest current CO2 emissions rate of any state from its coal-fired power 

plants, this represents a reasonable and needed goal. 

Comment 328: WY - The EPA's heat rate improvements are not representative for Wyoming 

sources.

Response 328: See section V.C. of the final rule preamble of the CPP for the EPA’s response to 

this comment and more information about Building Block 1. The EPA uses a 2.1% heat rate 

improvement assumption for Western EGUs in this final rule.

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

Commenters stated the goal for heat rate improvement (HRI) in the Proposed Rule is too high. 

Commenters said a HRI of 2% is a more realistic challenge for Wyoming's EGUs. Commenters 

said the EPA's position that the coal fleet average net heat rate can be reduced by 6% under 

BSER Building Block 1 is based on a hypothetical scenario and not based on real-world data and 

examples. Commenters stated the EPA relied upon apparent HRI for EGUs in Wyoming that 

were in error. [Heat Rate Improvements Rev 091514]. Commenters said the first example where 

erroneous data resulted in incorrect HRI is data reported for Dave Johnston Unit 4. Commenters 

stated new pollution control equipment was installed on Unit 4 in 2012 that required relocation 

of the flue gas flow monitoring equipment. Commenters said heat rate data collected after the 

monitoring equipment was relocated and calibrated showed an apparent 21% HRI for 2012. 

Commenters stated his organization reviewed subsequent submittals and determined that heat 

rate data, prior to the relocation of the monitoring equipment, was in error and grossly 
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overstated. Commenters said his organization's evaluation found that the HRI was only about 

1%. Commenters stated second, at Jim Bridger Unit 3, a reported 11% HRI was found to be in 

error because the difference in heat rates was later attributed to are-calibration of a flow monitor. 

Commenters said his organization's review confirmed there was no HRI for Unit 3.

Commenters stated according to the utility industry, based on historical data and real-world 

experience, potential HRI resulting from an EGU overhaul could restore a range of less than 1% 

to a maximum of 2.8% of a unit's net heat rate that has degraded since the last overhaul. 

Commenters said the EPA's expectation of a sustainable fleet-wide improvement of 6% 

therefore, is unrealistic and not consistent with real world application.

Commenters stated turbine upgrades provide the best opportunity for significant HRI. See the 

EPA's GHG Abatement Measures Document and PSC Letter. Commenters said Wyoming's fleet 

of existing EGUs has largely accomplished turbine upgrades, making further HRI upgrades 

difficult to achieve. Commenters stated his organization issued authorizations starting in 2007 to 

PacifiCorp Energy and Basin Electric Power Cooperative for turbine upgrades at their Jim 

Bridger and Laramie River Station facilities, respectively. Commenters said the majority of the 

upgrades have been completed over the last five years. Commenters stated because turbine 

replacement is typically done on a 30 year cycle, it is unreasonable to expect that either Jim 

Bridger or Laramie River Station could economically introduce and sustain a further 6% 

reduction in CO2 emissions by 2019. Commenters stated if the EPA chooses to move forward 

with the rule and the establishment of state emissions goals, Wyoming must be given flexibility 

to establish achievable HRI goals that are based on unit-specific performance, and the flexibility 

to choose a baseline period most representative of the unit's operation.

Comment 329: WY - Data Corrections

Response 329: For the EPA’s response to this comment, see the CO2 Emission Performance 

Rate and Goal Computation TSD for CPP Final Rule supporting the final CPP. Also see section 

VI of the preamble discussing EPA uses of 2012 data to inform its baseline.

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

Commenters stated the proposed rule incorrectly specifies Cheyenne Prairie Generating Station's 

(CPGS) combined cycle capacity as 220 MW name plate. The commenters said the actual name 

plate capacity of the CPGS combined cycle units is 100 MW. The commenters said EPA used 

this combined cycle capacity in the goal setting spreadsheet "20140602tsd-state-goal-datacomputation_1.xlsx". The commenters said the error lies in column "K" of the WYOMING row: 

"Under Construction NGCC Capacity (MW)." The commenters said the EPA dataset is correct 

on a source-by-source basis; thus, no changes are required in that instance. The commenters said 

modification of this spreadsheet value yields new interim year goals and a final 2030 state goal 

of 1,727 lbs. CO2/MWh (in lieu of 1,714 lbs. CO2/MWh).

Commenters stated 2012 Data Year is not a normal operating year for Neil Simpson II (NS2), 

Wygen I (WYG1) and Wygen II (WYG2). Wygen III (WYG 3) is included for an unaffected 

source reference; see details on each source below: 
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a. Neil Simpson II - based upon routine operations over the past 4 years, 2012 

represented an unusually low capacity factor for the facility; a more representative year is 

2013, which is neither the highest nor the lowest year, but a good representation at 94% 

capacity as opposed to 81% capacity in 2012. 

b. WYGEN 1 - based upon routine operations over the past 4 years, 2012 represented an 

unusually low capacity factor for the facility; a more representative year is 2013, which is 

neither the highest nor the lowest year, but a good representation at 92% capacity as 

opposed to 89% capacity in 2012. 

c. WYGEN 2 - based upon routine operations over the past 4 years, 2012 represented an 

unusually low capacity factor for the facility; a more representative year is 2013, not the 

highest or the lowest year, but a good representation at 83% capacity as opposed to 71% 

capacity in 2012. 

Commenters requested that the agency change the data in its final rule to accurately reflect Black 

Hills' newer generation fleet. The commenters said the changes call for changes in the EPA rule 

that alter 2012 Data year and also alter the state's 2020 interim goal and 2030 final goal. The 

commenters said these goals will be modified, but as other numbers may also change, the 

commenters will not suggest to the EPA what the state's goals should be in the final rule. 

Comment 330: WY - The EPA must commit to a consistent timeframe for the baseline and 

compliance in this proposal

Response 330: See section VI. 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 the EPA proposed a compliance period of a rolling three year average while 

using a single year, 2012, to determine the baseline for this Proposed Rule. Commenters said if 

the EPA is going to base compliance on a three-year rolling average, then the baseline for this 

Proposed Rule must also be based on a three-year average to ensure consistency for the proposed 

emission reductions. Commenters stated the EPA must commit to a consistent timeframe for the 

baseline and compliance in this proposal. 

Commenters stated if the EPA chooses to use a three-year average for the baseline emission limit 

in this proposal, careful consideration should be given to the data used. Commenters said his 

organization found discrepancies with regard to several EGUs. Commenters stated the 

supplemental CO2 emissions data from 2010 and 2011 provided by the EPA in October, 2014 

indicated that CO2 emissions from the three coal-fired EGUs at the Laramie River Station were 

equal, which differs from the data available in the EPA Air Markets Program. 

http://ampd.epa.gov/ampd (October 31, 2014). Commenters said furthermore, WDEQ notes that 

the hours of operation for the three EGU units range from 6,877 to 8,422 in 2010 and 7,135 to 

8,385 in 2011 making equivalent CO2 emissions from these three units statistically impossible.
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Commenters stated additionally, his organization notes discrepancies between the supplemental 

EPA technical data and the EPA Air Markets Program for CO2 emissions in 2011 for the Wygen 

I and the Wygen II facilities.

Commenters stated the scope of this proposed rule is unprecedented and requires the utmost 

diligence in insuring the information used is accurate. Commenters said if the EPA does not use 

reliable data, then it is acting in an arbitrary and capricious manner. Commenters stated his 

organization urges the EPA to perform a thorough quality assurance review of any data that it 

relies upon.

Comment 331: WY – BB3

Response 331: The EPA has revised its block three quantification based on comments and our 

further consideration. See section V.A. and V.E of the final rule preamble for more information 

about building block three.

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

Commenters stated that, the agency did not adequately demonstrate non-air environmental 

impacts and energy requirements of Building Block 3. Commenters said, Wyoming will have 

significant and unique non-air environmental impacts. Commenters said, that the rule is a direct 

violation with the CAA.

Commenters stated that, Building Block 3 which replaces carbon intense electrical generation 

with zero carbon generation does not consider Wyoming's unique circumstances. Commenters 

said that Wyoming produces 4,369,107 MWH of wind energy per year and 85% of which is 

exported to South Dakota, California, Utah, Oregon, Washington, and Idaho. Commenters said 

that if required by the rule, these states will come to Wyoming to purchase more wind energy 

and Wyoming will also need additional wind energy to meet the regulation. Commenters said, 

the effect of Building Block 3 will be additional wind energy projects.

Commenters stated that, Wyoming's greatest challenge to siting the wind farm is the affects it 

has on the habitat of the Greater Sage-Grouse (Centrocercus urophasianus). Commenters said 

that the increase level of wind energy expected would negatively impact the Greater SageGrouse's core habitat. Commenters said that EPA had failed to look at the impact of other species 

such as the bald eagles and bats. Commenters said that EPA failed to look at the non- air impacts 

of the proposed rule.

Comment 332: Building Blocks 3 and 4 should be used for compliance purposes only, not state 

goal setting.

Response 332: The EPA has revised its block three quantification based on comments and our 

further consideration. See section V.A. and V.E of the final rule preamble for more information 

about building block three. The EPA has determined that demand-side EE programs (proposed 
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building block 4) are not a component of the final BSER. See section V.A.3 of the preamble for 

discussion of this issue.

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

Commenters stated the Proposed Rule claims that states should be able to dramatically increase 

their use of renewable resources by the adoption of "best practices," meaning every state should 

adopt renewable portfolio standards ("RPS") and most of those who have already done so should 

adopt more aggressive standards. Commenters said the amount of renewable power EPA thinks 

can be brought on line within the compliance timeframes of the rule is not based on accurate 

assumptions and, as a result, is not reasonable or feasible. Commenters added Building Block 3 

reveals EPA's fundamental misunderstanding of state RPS programs (which the State of 

Wyoming has not adopted) and confuses EPA's role as an environmental rather than an energy 

regulator. Commenters agreed with the Commission's conclusion with respect to EPA's specific 

determination of Building Block 3 in Wyoming, that "EPA started its Wyoming calculation with 

the wrong number, applied an unrealistic growth factor and reached a wrong conclusion." 

Commenters said in calculating Wyoming's proposed compliance rate, EPA included all wind 

generation in the state, despite the fact that several wind facilities export power out of state. 

Commenters said renewable energy exported out of Wyoming should not be included in setting

Wyoming's requirement. Commenters estimated that the effect of this error improperly increases 

the stringency of the Wyoming goal by 10%.

Commenters stated EPA proposed two ways to calculate a generation shift resulting from the 

application of Building Blocks 3 and 4, either by replacing all historical fossil generation on a 

pro rata basis or by replacing historical fossil generation on a prioritized basis. Commenters said 

EPA requests comment on which approach better reflects the BSER, and commenters answered 

that neither approach reflects the BSER and EPA should not adopt either one. Commenters said 

BSER is a system of emissions reduction - it is not a system of generating-source elimination, 

nor is it a system of maximum emissions reductions. Commenters said the approach EPA used in 

the June 2014 proposal is appropriate and should not be changed in the final rule. Commenters 

said EPA explains that the change in methodology proposed in the NODA may be warranted in 

order to ensure consistency in application among the various building blocks; however, such an 

understanding assumes that incremental renewable generation and incremental generation 

avoided through energy efficiency are equivalent to fossil generation. Commenters said in 

reality, incremental renewable energy and energy efficiency cannot meet baseload requirements 

due to the variable nature of these resources. Commenters said the best system of emission 

reduction is most appropriately based on a system that augments - not replaces - historical fossil 

generation. Commenters said this allows states to achieve meaningful emissions reductions by 

prioritizing operation of less carbon-intensive resources while using baseload fossil generation to 

backstop functionality and reliability of the national electric system. 

Commenters stated EPA needs to update the 2 CPP approaches for calculating renewable energy 

deployment targets or goals for BB3 in order to analyze and select the BSER.

Comment 333: New England - general
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Response 333: For the EPA’s response to this comment, see the CO2 Emission Performance 

Rate and Goal Computation TSD for CPP Final Rule supporting the final CPP.

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

Commenters asserted that it is not well appreciated that New England's mix of power generation 

resources have resulted in a generation fleet with one of the lowest carbon emission intensities of 

any region in the country. The commenters said with very little coal and significant nuclear, 

hydro-electric and natural gas generation, the regions generation portfolio emits 828lbs/MWh of 

carbon dioxide, more than 30% below the national average of 1,230 lbs/MWh. 

Commenters said in New England the largest sources of greenhouse gas emissions are the 

transportation sector (44.5%) and emissions from space heating (29.6%); power generation is 

only the third source of emissions (21.2%) in New England; thus the significant focus should be 

placed on those sectors while continuing to drive for a cleaner power generation footprint. 

Commenters said New England has made significant improvements in lowering its carbon 

emissions footprint; since 2001, New England has reduced emissions by 17%, driven primarily 

by a 30% reduction in emissions from the power generation sector. The commenters said EPA 

should acknowledge, recognize and credit these efforts in the final rule. 

Comment 334: TX, AR, LA - complex practical issues - three RTOs, potentially three state 

plans

Response 334: See section VIII 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:

Complying with multiple SIPs. Commenters said the proposed rule raises many complex 

practical issues, including potentially having to comply with multiple state implementation plans 

and the complexities of operating in multiple RTOs. The commenters expressed concern about 

the many complex practical issues that are raised by the proposed rule, and the ETCs urge EPA 

to consider these practical issues and strive to give clear guidance to states and stakeholders 

when drafting the final rule. The commenters said first and foremost, because the ETCs own 

plants in Texas, Arkansas, and Louisiana, we are concerned about having to comply with 

potentially three separate state implementation plans. The commenters said in addition to added 

compliance costs in dealing with three states, there are many unanswered questions such as:

How will out-of-state minority owners of a particular coal plant be treated under that state's SIP

ETEC has a 50MW minority interest in the Turk coal plant in Arkansas, yet ETEC imports and 

consumes that power in Texas - how will Arkansas's SIP treat ETEC's minority ownership in 

Turk and will ETEC be unfairly treated by Arkansas 

The same concern would hold true for the ETC's plants in Louisiana. 
364

How will hydropower imported from the Southwestern Power Administration's system be treated 

by Texas 

Which agency (PUCT, TCEQ, or perhaps some new agency) in Texas will be responsible for 

enforcing the Texas SIP and how can state laws be crafted to ensure equitable enforcement

Operating in multiple RTOs. Commenters said another unique concern facing the ETCs is that 

they currently operate in three RTOs - SPP, MISO, and ERCOT. The commenters said the 

footprint of these three RTOs spans more than 21 states, with each state having different 

generating portfolios, different emission targets, and potentially different individual SIPs or 

some combination of individual SIPs within regional plans. The commenters said since the RTO 

model is currently based on the lowest-cost electricity, how is that reconciled with RTOs 

suddenly considering the environmental impacts of generating units. The commenters said 

having said that, a RTO solution/approach appears to be better than a state-by-state approach 

given the market structures associated with the RTOs, particularly for entities such as the East 

Texas G&Ts that own power plants in multiple states and are participants in multiple RTOs.

Comment 335: Raise the targets for TX, AR, and LA by 300 lb/MWh (or one-half in each state), 

or alternatively, replace Building Block #2 with end-of-useful-life requirement

Response 335: For the EPA’s response to this comment, see the CO2 Emission Performance 

Rate and Goal Computation TSD for CPP Final Rule supporting the final CPP.

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

Raise state targets in TX, AR, and LA. Commenters said in addition to removing the interim 

goals and delaying compliance by five years, the East Texas Cooperatives ask that EPA consider 

increasing emissions targets for Texas, Arkansas and Louisiana by 300 lbs/MWh (or one-half in 

each state). The commenters said currently, the three states in which the ETCs own generation 

have above average reduction requirements of approximately 600 lbs/MWh. The commenters 

said these targets create a higher burden for the Cooperatives and the other utilities in these 

states, and the severe negative economic impacts would be reduced if the targets were raised. 

The commenters said the concept is that reductions for 2020 and each year beyond that through 

2029 would be reduced by 50%. The commenters said for example in Texas the 2020 reduction 

would be 1,107lbs/MWh instead of 930 lbs/MWh, as compared to the 2012 base case rate of 

1,284lbs/MWh.

Commenters said increasing the emissions target by 300 lbs/MWh in Texas, Arkansas and 

Louisiana will positively impact the East Texas G&Ts by reducing the requirements by roughly 

half (e.g., two instead of four coal plants retired, replacement capacity reduced by half, impact on 

gas and transmission externalities by half - resulting in $1.3 billion decrease from the $2.9 billion 

impact).

Replace BB2 with end-of-useful-life requirement. Commenters said alternatively, because many 

projected closures are at plants that have many years left on their useful life, EPA could consider 

eliminating building block #2 - re-dispatch - and instead just allow those plants to live out their 
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useful lives before being retired. The commenters said this approach would involve replacing redispatch with the assumption that the retirement of the units at the end of their lives achieves this 

portion of the requirement, thus reducing the annual carbon emission targets from 2020 to 2029. 

The commenters said the remaining three building blocks would remain in effect. The 

commenters said three of the four east Texas G&Ts' coal projects that are projected to be retired 

were built in the 1980s and as such have useful lives beyond 2030, and the fourth plant projected 

to be retired went into service in 2010. The commenters said allowing these plants to live out 

their useful lives before being retired would greatly reduce the negative financial impact on the 

cooperatives.

Commenters said essentially what this proposal would do to the G&Ts is require them to reduce 

the output from coal units unless they can otherwise achieve the efficiency target in building 

block #1, as well as pursue renewables and energy efficiency measures at the rates assumed by 

EPA for the other two building blocks, which as previously stated, are aggressive. The 

commenters said eliminating building block #2, and allowing the coal projects to operate until 

the end of their useful lives would help the East Texas G&Ts by reducing the impacts by roughly 

half (e.g., two instead of four coal plants retired, replacement capacity reduced by half, impact on 

gas and transmission externalities by half - resulting in $1 .3 billion decrease from the $2.9 

billion impact). The commenters said the results of this mitigation case are very similar to the 

300 lbs/MWh reduction case for the East Texas G&Ts.

Comment 336: RGGI States

Response 336: See section VIII 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 requested that EPA add several provisions to the final version of the rule to 

facilitate the use of RGGI as a CPP compliance mechanism. The commenters said because RGGI 

requires specific CO2 emissions reductions and EPA's CPP proposes emissions rate reductions 

(although states are permitted to convert to a mass-based target), EPA should ensure that it 

appropriately translates its emissions rate targets into mass-based targets for the RGGI states. 

The commenters said EPA's emissions reduction targets should be updated periodically in states 

that utilize the mass-based approach to take into account changes in electric system operations.

Commenters stated EPA should specifically state in the final rule that RGGI is an appropriate 

CPP compliance mechanism and also should recognize the emissions reductions already 

achieved by the northeastern states pursuant to RGGI in assessing whether a state or regional 

plan meets the CPP's requirements.

Comment 337: GA, SC, TN - Inclusion of under-construction nuclear generation dramatically 

increases the stringency of goals in only three states: GA, SC, and TN; significant compliance 

risk results.
366

Response 337: See section V of the final rule preamble of the CPP. Under construction nuclear 

is not part of BSER quantification in this final rule

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

Commenters stated that the inclusion of under-construction nuclear generation dramatically 

increases the stringency of GA, SC, and TN goals and presents unique compliance risks of the 

under-construction units (the loss of a single unit's generating capacity would be so significant).

Commenters stated that the EPA's proposal to include expected generation from new, underconstruction nuclear facilities in setting state goals affects only three states' goals: Georgia, 

South Carolina, and Tennessee. Commenters said that whereas the other aspects of EPA's 

proposed BSER "building blocks" increase the stringency of nearly every state, EPA's proposal 

for under-construction nuclear singles out and penalizes the three states that have done the most 

in recent years to replace their emitting fossil generators with new, zero-emission generation. 

Commenters indicated that due to the large size of the five under-construction generators that 

EPA singles out for this unfair treatment, Georgia, South Carolina, and Tennessee's goals are 

14%, 22%, and 14% more stringent, respectively, than these goals would be without including 

under-construction nuclear. 

Commenters indicated that the EPA's incorporation of 90% of the expected generation from the 

five under-construction reactors in state goals creates compliance risks for Georgia, South 

Carolina, and Tennessee that are unlike those faced by any other state. The commenters said that 

in Georgia's case, under-construction nuclear generation accounts for 31% of the emission 

reductions EPA expects Georgia to achieve, relative to the 2012 baseline. Commenters indicated 

that this impact would be even greater if the EPA adopts the proposed changes to the goalcomputation methodology that are discussed in the October 30 Notice of Data Availability. 

Commenters said that the required reduction from under-construction nuclear is the single largest 

component of Georgia's required reductions, and is greater than the reductions the EPA projects 

from RE, EE, and at-risk nuclear generation combined. Commenters added that because Georgia 

is already expected to increase the capacity factor of its natural gas combined cycle (NGCC) 

units to 70% under the Proposed Rule, if the under-construction nuclear facilities fail to come 

on-line, or are later shut down due to safety or other unforeseen reasons, Georgia would have to 

more than double the already ambitious levels of RE and EE that EPA expects the State to 

develop in the coming years just to meet the State CO2 emission goal. Commenters said 

therefore, if the EPA's assumptions about the level of generation that the two under-construction 

nuclear facilities in Georgia will produce by 2020 are incorrect, Georgia will likely be unable to 

meet its emission goal.

Commenters stated that the size of the five under-construction nuclear facilities, as well as their 

high expected capacity factor, thus present compliance risks for Georgia, South Carolina, and 

Tennessee that are unlike those faced by any other state. Commenters stated that the other 

building blocks on which state goals are based generally involve relatively small changes in 

generation and emission, and the loss of these compliance options could theoretically be made up 

for through increases in other compliance measures. Commenters said that by contrast, the loss 

of even one of the 1,117 MW under-construction Vogtle reactors in Georgia would lead to a 

compliance gap of nearly 9,000,000 MWh in a single year. Commenters indicated that to make 
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up for such a gap, Georgia would have to obtain an amount of new, carbon-free electricity 

equivalent to the annual electrical output of more than 11 large wind farms -putting aside that 

wind, unlike nuclear energy, is not a viable baseload power source in Georgia.

Commenters stated that the magnitude of this compliance risk from a single facility dwarfs that 

faced by other states. Commenters noted that states that fail to complete construction of a single 

proposed wind farm or fail to increase the capacity factor of one of the NGCC units in the state 

to the levels anticipated by EPA will also face a compliance deficit, but the relatively small size 

of this deficit means that it can relatively easily be made up. Commenters said that for Georgia, 

by contrast, the loss of a single under-construction reactor will all but guarantee that the State 

will fail to meet its goal. Commenters stated that this aspect of EPA's proposal therefore puts 

Georgia and the other two states with under-construction nuclear facilities, more than any others, 

on a dangerous high-wire for compliance.

Commenters indicated that even without including under-construction nuclear in the goal 

calculation process, Georgia's final emission target would still be extremely stringent. 

Commenters said that in particular, if under-construction nuclear generation were excluded from 

the goal calculation, Georgia would be expected to reduce its fossil emission rate from 1,598 lbs. 

CO2/MWh in 2012 to 970 lbs. CO2/MWh by 2030 -a decrease of 39 percent. Commenters said 

that in other words, EPA's incorporation of under-construction nuclear generation- apart from 

being unfair and illegal- is not necessary to ensure that Georgia is incentivized to further reduce 

emissions from existing EGUs. Commenters added that conversely, excluding the five underconstruction units from state goals would have almost no impact on the Proposed Rule's 

contribution to nationwide emission reductions. Commenters said that the five underconstruction units account for only 1.4% of the 2030 generation total that is included in the 

EPA's goal computations. Commenters stated that were the EPA to treat the five underconstruction reactors like new units (i.e., excluding them from the goal calculation, but allowing 

states to count MWh from these units toward compliance if the units are actually built), the 

national average emission rate would increase by only 1.2% compared to the rate as currently 

proposed. Commenters noted that consequently, despite exposing the three under-construction 

nuclear states and their citizens to an insurmountably high compliance penalty if even a single 

reactor is delayed or later decommissioned, the inclusion of these five units in state goals has 

almost no impact on the stringency of the Proposed Rule. Commenters concluded that in light of 

the unfairness of singling out these three states, and the massive risk to which this aspect of the 

Proposed Rule exposes Georgia, the EPA should abandon its proposal to include generation from 

under-construction nuclear facilities in calculating state goals.

Comment 338: WA & OR - By establishing 2012 as the baseline year from which carbon 

reductions must be achieved, the EPA has assumed artificially low emissions rates for both 

Washington and Oregon.

Response 338: See section VI of the final rule preamble of the CPP for a discussion of baseline 

adjustments made to account for outlier hydro generation levels in in 2012.

The following are summaries of the specific public comments under this comment:
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Commenters stated by establishing 2012 as the baseline year from which carbon reductions must 

be achieved, the EPA has assumed artificially low emissions rates for both Washington and 

Oregon. Commenters said Northwest hydro output was at 128% of normal in 2012. Commenters 

stated the result was carbon emissions in Oregon and Washington that were 1.6 million and 5.5 

million metric tons lower than the average of the last ten years, respectively. Commenters stated 

this means that both coal- and gas-fired plants ran at capacity factors significantly below the 

historical average. Commenters said the number of combined MWhs produced by coal and 

natural gas in Oregon in 2012 was 14.3 million. Commenters stated this compares to 19.8 million 

MWhs in 2010 and 19.3 million MWhs in 2009. Commenters said in Washington, 2012 

combined coal and natural gas output was 9.2 million MWhs, while it was 18.9 million MWhs in 

2010 and 19.4 million MWhs in 2009 (more than double the 2012 output).

Commenters stated despite these massive discrepancies in fossil output (and the corresponding 

emissions), the EPA is requiring Washington to reduce its carbon emissions by 72 percent from 

below average 2012 levels, and Oregon by 48 percent. Commenters said when one compares the 

emission rate reduction goals to prior years with lower hydro output and higher emission rates, it 

is clear that these percentage reductions are significantly greater when based on these higher 

carbon years. Commenters stated the consequence is that EPA's goals will likely be unattainable 

in years with low hydro output when fossil generators will need to run at higher capacity factors, 

and therefore, do not represent the true BSER for these states. Commenters said the EPA should 

not penalize Oregon and Washington simply because these states rely heavily on a clean, but 

variable, energy source.

4.12 OTHER

Section 4.12 covers public comments related to other final and interim goals calculation issues. 

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: Aggressive CO2 reduction goals may place smaller utilities at economic 

disadvantage and may affect reliability

Response 1: For the EPA’s response to this comment, see the Regulatory Impact Analysis for 

the Clean Power Plan Final Rule, EPA-452/R-15-003 supporting the final CPP.

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

Commenters indicated that Michigan's 41 municipal utilities, as well as the vast majority of 

Michigan's 10 electric cooperatives, are not rate-regulated by the Michigan Public Service 

Commission (Commission). Commenters said that Commission authority is limited to certain 

statutory requirements such as compliance with the state's ten percent RPS by 2015 and the 

state's EE target of a one percent reduction in annual retail electricity sales. Commenters said that 
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it is important to note, however, that these utilities typically lack the size and/or capability of 

larger investor-owned utilities (IOU) in both their energy requirements and magnitude of energy 

generation. Commenters said hence, additional burdens to meet aggressive carbon dioxide (CO2) 

reduction targets may place these smaller utilities at an economic disadvantage that in some 

cases would raise the question of continued reliability in already constrained areas of the state.

Comment 2: The EPA must resolve implementation issues. The EPA must provide full set of 

outputs and documentation of IPM analysis

Response 2: For the EPA’s response to this comment, see section VIII of the final rule preamble 

for the CPP and the CO2 Emission Performance Rate and Goal Computation TSD for CPP Final 

Rule supporting the final CPP. The Regulatory Impact Analysis and corresponding power sector 

modeling and documentation in the docket for this final rule provide for an evaluation of the 

model. The system-wide impacts of a compliance scenario informed by the model are available 

through year 2054.

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

Commenters said that prior to final promulgation, the EPA should, at a minimum, fully evaluate 

the broad scope of implementation issues that must be resolved and the corresponding regulatory 

agencies and other parties involved. Commenters also stated that the Integrated Planning Model 

(IPM) output files provided by the EPA do not allow for a proper evaluation of the suite of 

measures that states and affected sources are projected to utilize under the proposed rule.

Commenters indicated that the EPA has only provided the IPM "parsed" model output files only 

for one select model compliance year for each of the cases run, which does not allow for a full 

evaluation of state-by-state compliance actions across the full timeline the proposal 

encompasses. Commenters also indicated that the model year provided is not consistent between 

the cases run. Commenters said additionally, the outputs for the IPM model run consisting of 

only building blocks 1 and 2 appears to be based on a single integrated model compliance year 

which does not allow for proper assessment of the emission caps as utilized by 

EPA. Commenters indicated that full outputs and documentation are critical to the evaluation of 

the rule, particularly as the state agencies responsible for rule administration do not possess the 

tools or resources to assess potential electric sector compliance strategies.

Comment 3: The EPA should establish formal process that allows states and other stakeholders 

to identify technical errors that requires the EPA to respond substantively

Response 3: The EPA appreciates the comments and has revised the goals, EPA received 

significant feedback through public outreach and subsequent comment submittal to the 

document. It has made a significant number of updates to its 2012 data and methodology for 

quantifying BSER based on these comments.

The following are summaries of the specific public comments under this comment:
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Commenters argued that EPA should include a mechanism for making technical corrections 

based on a review of the data and assumptions used in calculating state goals. The commenters

EPA should be cognizant that errors may occur, and likely have occurred, in the formulation of 

the CPP. Toward that end, the commenters were supportive of a formal process that allows states 

and other stakeholders to identify errors that requires EPA to respond substantively, especially if 

any error(s) has an impact on compliance costs. 

Comment 4: Commenters stated defined targets by 2020 should be maintained as a requirement 

of the rule as well as interim targets for 2025 without allowance for averaging.

Response 4: See section I.A. of the final rule preamble of the CPP for the EPA’s response to this 

comment.

Comment 5: Commenters stated that they favor EPA recognizing states need to reduce 

emissions and that there is a need to consider future scenarios. 

Response 5: The EPA’s CO2 performance rates and state goals are based on determining the 

level of emission performance that reflects application of the BSER. Therefore, the emission 

guidelines will require the degree of improvement that the agency has determined is achievable 

for states.

The EPA agrees that the calculation of the emissions performance levels that reflect BSER 

should reflect the potential for reducing generation by affected EGUs through increase in 

renewable energy generation. The agency disagrees that calculations of the emissions 

performance levels achievable through the BSER should be based on projections of the future 

state of the electricity system, such as assumptions about future plant retirements. We believe 

that historical data provides a stronger basis for this rulemaking. We are applying the BSER, as 

we have done in calculating other section 111(d) standards, to a defined population of existing 

affected sources, represented in this case by the generation of the source category in the 2012 

adjusted baseline. This provides an empirical historical baseline against which we define the 

performance rates and their state goal equivalents. It is essential that we apply the building 

blocks in a way that avoids creating a level of stringency in the performance standards for 

affected EGUs that goes beyond what we have determined to be the BSER – while at the same 

time ensuring that equations apply the building blocks to generate performance standards that 

represent the full application of the BSER to the affected EGUs. See final CPP preamble sections 

V-VII.

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

Commenters stated that the targets need to recognize that states can and should do more to 

reduce carbon emissions. Commenters stated that the EPA based the reductions on the agency's 

calculations of what each state could do. Commenters stated that the EPA need to set standards 

that push states to do more.
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Commenters stated that the EPA's calculations on the states' best system of emission reductions 

need to account appropriately for the ongoing changes in state energy sources. Commenters 

stated that the EPA should ensure, for example, that it fully accounts for the on-going retirement 

and reduced demand for coal-fired power generation created through growth in renewable energy 

sources.